Cretaceous petroleum system elements in the Komombo Basin, Egypt

The Komombo Basin, located in the southeasternmost region of the Western Desert, displays a series of en echelon half-graben orientated NW–SE (Bosworth et al. 2008; Ali et al. 2018, 2022a; Said and Sakran 2020). The basin formed due to Cretaceous intracontinental rifting, with numerous growth normal faults intersecting the basin (Ali et al. 2022a). These faults predominantly trend NW–SE, along with some NE–SW orientations. Ali et al. (2022a) identified four distinct synrift and post-rift sequences within the Komombo Basin. Moreover, two unconformities were documented, corresponding to basement uplift events during the Albian–Cenomanian and Oligocene–Miocene (Ali et al. 2022a).

The well correlation analysis of nine wells reveals that the Komombo Basin is characterized by a substantial sedimentary sequence (Fig. 2). This sequence spans from up to 1000 to 2200 m of Cretaceous sediments, which are overlain unconformably by 200–400 m of Pliocene Nile fill. The large thickness variation within the Cretaceous sequence of the Komombo Basin is correlated with the influence of the major growth normal faults (Ali et al. 2022a). Within the Cretaceous succession, seven formations are identified, ordered from older to younger, as the Six Hills, Abu Ballas, Sabaya, Maghrabi, Taref, Quseir and Dakhla formation (Fig. 2). The basement rocks, which are Proterozoic in age (600–900 Ma) (El-Gaby et al. 1988; Stern 1994), are unconformably overlain by the Six Hills Formation. This formation contains preserved palynomorphs dating back to the Berriasian–Barremian (Selim 2016). The Six Hills Formation primarily comprises well-sorted medium- to coarse-grained sandstone intercalated with layers of mudstone and fine-grained siltstone (Selim 2016; Ali et al. 2022a). It is further divided into seven members labelled A–G (Fig. 2).

The Six Hills Formation is unconformably followed by the Aptian Abu Ballas Formation. This formation is characterized by highstand deposits comprising shallow-marine mudstone with a consistent thickness of c. 40 m (Barthel and Boettcher 1978; Wycisk 1994; Ali et al. 2022a). The Sabaya Formation unconformably overlies the Abu Ballas Formation and dates from the Albian–Early Cenomanian. It primarily comprises cross-bedded sandstone, alternating with thin layers of mudstone (Wycisk 1994; Selim 2016). The Late Cenomanian Maghrabi Formation follows the Sabaya Formation conformably, and is primarily composed of variegated mudstone with occasional interbeds of sandstone and siltstone. The average combined thickness of the Sabaya and Magharbi formations is approximately 300 m (Fig. 2). The Turonian Taref Formation, characterized by predominantly clastic sediments, ranges in thickness from 70 to 205 m and includes mudstone alongside well-sorted fine-grained sandstone and siltstone (Fig. 2) (Selim 2016; Ali et al. 2022a).

The Quseir Formation, dating from the Late Turonian–Santonian, primarily consists of dark grey mudstone in its lower portion, transitioning to alternating layers of claystone, siltstone and sandstone in the upper section, with an average thickness of 150 m (Fig. 2). It is overlain conformably by the Dakhla Formation, which ranges in age from Campanian to Maastrichtian. The Dakhla Formation is predominantly composed of open-marine black shale, interspersed with interbeds of sandstone, siltstone and limestone (Selim 2016; Ali et al. 2022a). Its thickness varies, ranging from 128 to 680 m (Fig. 2). Within the upper portion of the Dakhla Formation, intricate multi-channel systems of Nile fill are observed, consisting of Pliocene silts, sands and gravels. The thickness of these Nile fill deposits ranges from 244 to 469 m (Fig. 2).

An interpretation of 20 seismic profiles was conducted to delineate the primary stratigraphic sequences and structural features within the Komombo Basin (Fig. 1). The post-stack time-migrated seismic data were acquired and processed in 2005 by WesternGeco. These profiles are categorized into NE–SW-trending dip lines and NW–SE-orientated strike lines, with a 5 s record length in two-way time (TWT). The seismic interpretation includes seismic-to-well ties, horizon interpretation and fault delineation (Ali et al. 2022b, 2023a, 2024b; Ismail et al. 2023). An interpretation of eight horizons was conducted, utilizing well data and considering reflection properties such as amplitude, reflectivity, frequency and configuration (Figs 3 and 4).

Data from nine wells (ABSE-1, AB-1, AB-5, AB-6, Kom-1, Kom-2, Kom-3, A-1 and Mem-1: refer to Fig. 1) were utilized to achieve the study's objective. These wells provided crucial information, including formation tops, check-shot data, well logs, geochemical data, core photographs, borehole images, dipmeter, X-ray diffraction (XRD) analysis, as well as helium porosity and permeability measurements. Penetrating the entire Komombo stratigraphic section and reaching into the Proterozoic basement, with the exception of wells AB-5 and AB-6, these wells varied in total depth, ranging from 1141 m below sea level (bsl) in Kom-3 to 2515 m in ABSE-1 (Table 1; Fig. 2). Geochemical analysis was conducted on 778 samples obtained from six wells (ABSE-1, AB-1, Kom-1, Kom-2, Kom-3 and Mem-1) to identify the primary source rocks within the Cretaceous sediments of the Komombo Basin and to understand their geochemical characteristics. These samples were analysed at the Stratochem Laboratory in Cairo, Egypt. The dataset includes various parameters such as total organic carbon (TOC), vitrinite reflectance (%R_o), oxygen index (OI), hydrogen index (HI), T_max, and S₂. However, some of these parameters were unavailable for certain wells or within specific source rocks (Table 1; Figs 5–8). To assess the potential source-rock viability and understand the variations in organic matter quality and thermal maturity, four distinct types of plots were employed (Figs 5–8): (i) HI v. OI plot following van Krevelen (1961); (ii) TOC v. Rock-Eval pyrolysis S₂ plot after Langford and Blanc-Valleron (1990); (iii) T_max v. HI plot based on Espitalié (1986); and (iv) %R_o v. HI plot after Espitalié (1986).

The integration of petrophysical and petrographical analyses is commonly used to understand how mineralogical composition and diagenetic features affect the petrophysical properties and reservoir quality (e.g. Abuhagaza et al. 2021; Elhossainy et al. 2021; Safa et al. 2021; Nabawy et al. 2022). To study characteristics of the reservoir rocks in the Komombo Basin, two core intervals were collected from two wells: the first interval from the Kom-2 well covers the A Member and altered Proterozoic basement rock from 2420–2435.2 m bsl, while the other core interval spans the Albian–Cenomanian Sabaya and Maghrabi formations in well AB-6, totalling 188 m in length. A total of five representative thin sections were collected from the first core interval and six thin sections from the second core interval. All of these samples were impregnated with blue plastic resin prior to thin sectioning. The blue colours visible under plain polarized light indicate the type and frequency of visual porosity present in the rock. Petrographical examinations were conducted on all thin sections, and considered facies assemblages, diagenetic features and reservoir quality. The mineralogical classification, based on the quartz–lithic–feldspar ratio, indicates the degree of sandstone maturity. The sandstones of the C Member of the Six Hills Formation were imaged using borehole image (BHI) logs, represented by Formation MicroImager (FMI) and dipmeter data, and petrophysical log response from the AB-1 well. Moreover, gamma ray (GR), density and neutron logs were utilized to evaluate the quality of the sandstone units within the Barremian D–G members of the Six Hills Formation. Reservoir facies analysis and characterization for all anticipated reservoirs have been conducted utilizing available datasets.

The main seismic sequences and structural elements in the Komombo Basin can be highlighted through the interpretation of dip and strike seismic profiles (Figs 3 and 4). The NE–SW-orientated seismic profile 02 spans 22.3 km, and crosses the depocentre and western flank of the basin perpendicularly. Profile 09 is orientated NW–SE and extends 22.8 km through the depocentre area within the Al Baraka oilfield (Figs 1, 3 and 4). Numerous normal faults that traverse the entire Komombo stratigraphic sequence and extend into the crystalline basement were observed within the NE–SW dip line. These faults are predominantly concentrated in the depocentre of the basin, creating half-graben, graben and horst structures (Fig. 3). Conversely, in the NW–SE-trending seismic profiles, most of the faults only penetrate the lower part of the synrift I sediments (Berriasian–Barremian Six Hills Formation) and the lower section of the Turonian–Santonian synrift II sequence (Fig. 4). Therefore, the seismic profiles (Figs 3 and 4) indicate that structural traps, mainly faults, dominate the Komombo Basin.

The seismic profiles revealed eight main horizons, each marking the tops of significant geological formations, including the crystalline basement, the B Member, the C Member, the D–G members of Six Hills and Abu Ballas formations, the Sabaya and Maghrabi formations, the Taref Formation, the Quseir Formation, and the Dakhla Formation, as well as Nile sediments. These formations display their maximum thicknesses within the depocentre of the basin (Figs 3 and 4). The top of the crystalline basement exhibits a distinct strong reflection with high amplitude. An uplift can be observed in the central region of the basin, situated between the Al Baraka and West Al Baraka oilfields (Fig. 3).

For the A–C members, the interpreted seismic profiles depict that the crystalline basement is followed by a thin seismic unit covering the A and B members of the Six Hills Formation (Figs 3 and 4). These members are grouped due to the minimal thickness of the A Member, which falls below the vertical resolution of the seismic data. The B Member is then found conformably overlain by the C Member of the Six Hills. Both sequences exhibit medium- to well-stratified reflections with medium–high amplitude. The distribution of the A–C members is primarily confined to the depocentre of the basin, noticeably absent from the western and northwestern flanks, as indicated by seismic and well data (Figs 2–4). Ali et al. (2022a) documented the seismic characteristics of the rest of the succession from the Barremian D–G members to the Pliocene Nile sequences.

The sedimentary succession of the Komombo Basin contains several shale units. Within these shale intervals, four distinct source rocks have been found by utilizing available geochemistry data. These source rocks are identified as the B Member of the Six Hills Formation, the upper Maghrabi Formation, the Quseir Formation and the Dakhla Formation (Figs 5–8).

The B Member source rock is predominantly composed of dark grey, laminated organic-rich mudstone (Abdelhady et al. 2016; Selim 2016; Ali et al. 2018). This source rock has been penetrated by four wells: AB-1, Kom-1, Kom-2 and ABSE-1 (Figs 1 and 2). The B Member displays TOC values ranging from 0.5 to 3.74 wt%, with HI values ranging from 118 to 365 mgHC g⁻¹ TOC (Fig. 5). However, the majority of samples exhibit values of about 1.5% TOC and 250 mgHC g⁻¹ TOC. The OI values of the analysed samples vary between 11 and 232 mgCO₂ g⁻¹ TOC, while S₂ peaks, indicating the amount of hydrocarbons generated, range from 0.64 to 13.89 mgHC g⁻¹ rock. Furthermore, the T_max values of the B Member exhibit a wide range of between 429 and 456°C, with %R_o values varying from 0.95 to 1.29. Figure 5 illustrates that the TOC, HI, T_max and %R_o values in the three wells (AB-1, Kom-1 and Kom-2) located in the central part of the depocentre are higher compared to those in well ABSE-1 in the southeastern area of the Komombo Basin. However, well ABSE-1 exhibits larger OI values, ranging from 34 to 232 mgCO₂ g⁻¹ TOC, compared to the other wells (Fig. 5a).

The upper Maghrabi Formation source rock has been encountered by all drilled wells within the Komombo Basin, and its geochemical composition has been examined in six wells. Figure 6 illustrates that OI values are available only for two wells, Kom-3 and Mem-1, while S2 values are not available for wells ABSE-1, AB-1 and Kom-1. In addition, Kom-1 and Mem-1 lack %R_o measurements within the upper Maghrabi source rock. The TOC values of the upper Maghrabi range from 0.51 to 1.8 wt%, while the HI values span from 33 to 213 mgHC g⁻¹ TOC (Fig. 6). However, in well ABSE-1, the TOC values increase significantly to 5.94 wt%. The upper Maghrabi exhibits elevated OI values, ranging between 50 and 214 mgCO₂ g⁻¹ TOC, alongside relatively low S₂ values that vary from 0.18 to 2.33 mgHC g⁻¹ rock. In addition, the T_max values of the upper Maghrabi are high, ranging from 437 to 454°C, with an average of 442°C, while its %R_o values remain relatively low, ranging from 0.57 to 0.69 (Fig. 6). Overall, the upper Maghrabi source rock exhibits higher TOC and HI values in the depocentre of the basin compared to its shoulders (Kom-3 and Mem-1), with average TOC and HI values of 1.36 wt% and 100 mgHC g⁻¹ TOC, respectively (Fig. 6b, c). In contrast to the B Member source rock, the upper Maghrabi source rock encountered in well ABSE-1, situated in the southeastern sector of the basin, exhibits higher HI values compared to those observed in the depocentre, with a maximum value of 213 mgHC g⁻¹ TOC (Fig. 6c).

The Quseir Formation has variable TOC and HI values that range from 0.88 to 4.92 wt% and 14 to 225 mgHC g⁻¹ TOC, respectively (Fig. 7). Many samples exhibit a TOC of c. 2 wt% and an HI of c. 150 mgHC g⁻¹ TOC. In addition, OI values exhibit significant diversity, ranging from 13 to 277 mgCO₂ g⁻¹ TOC, accompanied by relatively elevated S₂ values, with a maximum value of 11.7 mgHC g⁻¹ rock. The %R_o values of the Quseir Formation range from 0.5 to 0.75, with T_max values falling between 423 and 448°C, with an average of 439°C (Fig. 7c, d). The distribution of HI values is consistent across the entire Komombo Basin, with wells displaying both low and high values (Fig. 7c). For instance, the Kom-3 well, situated on the western flank of the basin, exhibits values ranging from 53 to 225 mgHC g⁻¹ TOC, whereas the Kom-1 well, located in the depocentre, demonstrates values ranging from 14 to 218 mgHC g⁻¹ TOC (Fig. 7c). This trend also extends to TOC and S₂ values (Fig. 7b). However, there is a notable difference in T_max values between the depocentre and the basin shoulder. Wells in the depocentre (e.g. AB-1 and Kom-1) generally display relatively higher T_max values compared to those on the basin's shoulder (Kom-3: Fig. 7c). For example, the T_max values of the AB-1 well range narrowly between 444 and 448°C, while westwards, in the Kom-3 well, the T_max values decrease noticeably, ranging from 423 to 441°C.

Analyses of samples extracted from the Dakhla Formation reveal notable variations in both TOC and HI values. TOC values span from 0.56 to 8.33 wt%, while HI values range between 17 and 285 mgHC g⁻¹ TOC (Fig. 8). However, the majority of samples have TOC and HI values of c. 2 wt% and 150 mgHC g⁻¹ TOC, respectively. OI values for the analysed samples also fluctuate between 20 and 225 mgCO₂ g⁻¹ TOC, with S₂ peaks ranging from 0.09 to 16.52 mgHC g⁻¹ rock. Moreover, T_max values of the Dakhla Formation source rock display a broad range, varying from 416 to 445°C (Fig. 8c), alongside %R_o values of 0.42–0.69 (Fig. 8d). Despite having data available for only one well (Mem-1) from the basin's flanks, it is notable that the TOC and HI values in the depocentre wells are higher compared to Mem-1 well in the northwestern flank of the basin (Fig. 8c). T_max values show a consistent distribution across the entire basin, with values of less than 435°C in the shallow part of the Dakhla source rock increasing downward to 445°C in the lower portion of the Dakhla Formation (Fig. 8c).

The available datasets indicate that the Komombo Basin hosts three primary reservoir units: the A and C members of the Six Hills Formation, and the Sabaya and Maghrabi formations. In addition, potentially promising sandstones have been identified within the Barremian D–G members of the Six Hills Formation.

A total of 15.2 m of core encompassing the A Member reservoir, along with a thin portion of the Proterozoic basement, reveals the distinctive characteristics of the A Member of the Six Hills Formation (Fig. 9). It features non-marine gravelly sandstone interspersed with thin layers of sandy siltstone and mudstone, unconformably overlying highly weathered basement rocks (Figs 9 and 10). Through analysis of core photographs and thin sections, six primary sedimentary facies have been identified within the A Member reservoir: Sp (pebbly sandstone), Sx (cross-bedded sandstone), Sz (silty sandstone), Zs (sandy siltstone), Z (siltstone), and Msc (sandy and carbonaceous mudstone). These facies are further grouped into three main categories based on grain-size distribution: sandstone facies (Sx/Sp), siltstone facies (Z/Zs/Sz) and mudstone facies (Msc).

The sandstone facies (Sx/Sp) consists mainly of coarse- to medium-grained quartz sandstone, typically poorly to moderately sorted and predominantly cross-bedded (Figs 9b and 10c, d, g, h). Bedding planes are often defined by pebble intervals, with claystone mud lithoclasts commonly found at the base of fining-upward sequences (Fig. 9b, c). In addition, kaolinite and carbonaceous debris (coaly) are frequently observed features within this facies (Fig. 10d, g). The cross-bedded sandstone displays characteristics of being pebbly and slightly bedded at the base, transitioning to cross-bedded/laminated features towards the top (Fig. 9c). Furthermore, sharp and erosive basal contacts between facies Sx/Sp and other facies are commonplace, indicative of a high-energy depositional environment (Fig. 9b–d). The thin sections reveal that the sandstones are primarily composed of quartz, with lesser amounts of lithics, micas and detrital clays (Fig. 10c, d, g, h). The Sx/Sp facies displays pebble-grade, sub-angular quartz grains with poor to moderate porosity. The thin sections depict well-compacted sandstone with sutured and elongated grain contacts (Fig. 10d). In addition, most of the pores are partially filled with residual hydrocarbon (Fig. 10c). In contrast, the Sx facies shows predominantly angular to subrounded, medium- to coarse-grained quartz arenite with moderate compaction and low porosity (Fig. 10g, h).

The siltstone facies (Z/Zs/Sz) comprises dark and light grey, carbonaceous siltstone with a varying sand content (Figs 9 and 10a, e, i). It exhibits a sandy composition towards the base, transitioning to a silty composition towards the top, with distinct contacts with the overlying coarse-grained sandstone interval (Fig. 9c). These siltstone facies generally indicate a low-energy depositional regime, where sedimentation predominantly occurs through suspension fallout. The silty sandstone facies (Sz) displays a sublithic wacke texture (Fig. 9e), containing angular to sub-angular highly altered lithic fragments and fine quartz grains within a silt-grade matrix. This facies shows no obvious porosity and exhibits low–moderate compaction (Fig. 10a, b). In addition, the examined thin sections highlight the likely Zs/Sz facies, recognized by its poorly sorted quartz wacke composition, with fine–coarse quartz grains in a silt-grade matrix (Fig. 10e, f). This facies shows no visible porosity and exhibits low–moderate compaction, characterized by elongated and point contacts. In contrast, facies Zs, at a depth of 2427.73 m, exhibits a lithic wacke with a poorly sorted texture, comprising angular to sub-angular lithic fragments and quartz grains. The quartz grains are predominantly concentrated along laminae planes (Fig. 10i, j). The mudstone facies assemblage (Msc) encompasses dark to light grey, blocky to sub-blocky, pyritic, silty and sandy mudstone (Fig. 9d). A clear top contact is observed with the overlying pebbly sandstone (Sp). Unfortunately, no thin sections are available for this mudstone facies.

Four clay fractions were extracted from four distinct facies (Z, Zs, Sx and Msc) for XRD analysis to semi-quantitatively measure the total clay mineral contents within the A Member reservoir. The findings indicate that kaolinite clay mineral comprises the predominant component (>85%) within fine-grained facies (Zs, Z and Msc: sandy siltstone, siltstone and sandy mudstone), whereas chlorite is the primary clay mineral in the cross-bedded sandstone facies (Sx) (Fig. 11a). Porosity and permeability cross-plots (Fig. 11b, c) demonstrate that the porosity values of the sandy siltstone (Zs) and silty sandstone (Sz) facies fall within the range of 1.2–9.5%. Meanwhile, the horizontal and vertical permeability values vary from 0.01 to 1.2 mD and from 0.04 to 0.85 mD, respectively. Conversely, the pebbly sandstones (Sp) and cross-bedded sandstones (Sx) exhibit a higher porosity, ranging between 6.7 and 18.2%, along with relatively high horizontal and vertical permeability, ranging from 1.5 to 23 mD and from 0.75 to 17 mD, respectively (Fig. 11b–d). In addition, four porosity and permeability measurements were collected from the altered igneous rock to assess the petrophysical characteristics of the Pre-Cambrian basement, revealing very low porosities (1.5–2%) and permeabilities (<0.05 mD).

The C Member reservoir, similar to the A Member reservoir, is confined to the depocentre of the Komombo Basin (Figs 2 and 3). Its thickness varies, ranging from about 78 m in well Kom-1 to 120 m in well Kom-2 (Figs 2 and 12). Characterized by a coarsening-upward cycle, the C Member reservoir primarily comprises mudstone intercalated with interbeds of sandstone and siltstone (Fig. 12). Although no core photographs or direct porosity and permeability measurements are available for the C Member, effective porosity has been calculated using density and neutron logs in three wells (AB-1, Kom-1 and ABSE-1: Fig. 12). Despite the prevalence of mudstones in the C Member reservoir, numerous sand units with high porosity values have been identified. For example, in wells AB-1 and Kom-1, located centrally within the basin, sandstones ranging from 5 to 15 m in thickness exhibit high porosities of between 12 and 26% (Fig. 12). Conversely, the ABSE-1 well, situated in the southeastern part of the basin, reveals only two dominant sand units in the upper and lower portions of the reservoir, with an average porosity value of 10% (Fig. 12).

Borehole imaging data spanning 9 m is accessible from the AB-1 well, encompassing the middle section of the C Member reservoir (Fig. 13). Both the BHI and GR logs reveal isolated cross-stratified and horizontally stratified sandstone bodies encased within laminated mudstones (Fig. 13). Tabular and trough cross-bedded sets are evident within the cross-stratified sandstones, along with relatively minor occurrences of parallel-bedded sandstone (horizontally stratified). The dip angles of the cross-beds range between 12° and 37° in the ENE, SE and SW directions (Fig. 13). These sandstones primarily consist of fine- to medium-grained textures, occasionally exhibiting coarse-grained characteristics in certain sections.

The D–G members of the Six Hills Formation (Barremian) constitute the most extensive sedimentary interval within the Komombo Basin, with thicknesses varying from 250 m in the western flank (Kom-3 well) to 882 m in the depocentre (AB-1 well: Fig. 2). Generally, it displays a coarsening-upward cycle, characterized by medium- to coarse-grained sandstone interbedded with mudstone and siltstone layers (Figs 2 and 14). Effective porosity values in the AB-1, Kom-1 and ABSE-1 wells indicate several thick and promising sandstone reservoirs with high porosity values, reaching up to 15% within the D–G members reservoirs (Fig. 14). Neutron or density logs are unavailable in the other six wells to calculate the effective porosity within the sand units of the D–G members.

The well correlation reveals that the Sabaya and Maghrabi formations, which represent the Albian–Cenomanian reservoir, are predominantly composed of sandstones and shales, with occasional thin interbeds of siltstones (Fig. 2). These formations display thickness variations ranging from 170 to 457 m (Fig. 2). Typically, the interval demonstrates a fining-upward trend, with sandy facies predominating at the base and transitioning to silty and muddy facies towards the top of the reservoir. An examination of cored intervals and thin sections from AB-6 well reveals the composition of the Sabaya–Maghrabi reservoir as comprising five primary sedimentary facies groups (Figs 15–17): mudstone facies, siltstone facies, sandstone facies, heterolithic facies and gravelly facies.

The mudstone facies is characterized by a dark to moderate grey colour, featuring laminated to locally deformed mudstones. This deformation is often attributed to bioturbation or small-scale fractures. Throughout the Sabaya–Maghrabi reservoir, the mudstone facies is present at various depths, frequently interbedded with siltstone facies and occasionally with sandstone facies, delineating sharp planar boundaries (Figs 2 and 15a).

The siltstone facies displays a moderate grey to locally light grey colour, characterized by laminated to locally deformed siltstones. These siltstones occasionally contain abundant very-fine-grained sandstone. In addition, various-sized mudstone clasts are dispersed throughout these facies types. The siltstone facies lack calcareous cementation, visual porosity and oil staining. The siltstone facies occurs as beds of various thicknesses throughout the entire reservoir interval. It is primarily interbedded with mudstone and occasionally with sandstone facies (Figs 2 and 15a).

The sandstone facies exhibits various textural characteristics, including massive sandstone, deformed laminated sandstone and cross-laminated sandstone. The massive sandstone comprises light–medium brown sandstone with fine–medium sand sizes. It contains dispersed fine carbonaceous material (Fig. 15b). The deformed laminated sandstone is light grey, occasionally greenish grey, with a moderate silt content and very fine sand sizes. Small mudstone clasts are locally present (Fig. 15b). However, the cross-laminated sandstone consists of light grey sandstones with a silt content, featuring trough cross-bedding and no oil staining. Some intervals exhibit brownish ripple cross-laminated sandstone with fine sand sizes (Fig. 15b).

The heterolithic facies consists of two main types: sandstone-dominated and silt/clay-dominated heterolithic facies. The sandstone-dominated type is more common, featuring interlamination between light grey, lenticular to cross-laminated, locally bioturbated, and strongly deformed sandstone layers, along with dark–medium grey mudstone laminae (Fig. 15c). In certain intervals, this facies displays a distinct boundary between brownish-grey massive sandstone and cross-laminated to slightly deformed laminated sandstone-dominated heterolithic facies (Fig. 15c). Conversely, the silt/clay-dominated heterolithic facies often exhibits a fining-upward trend in grain size. It comprises light silt and dark grey clay intervals, displaying bioturbated and laminated to slightly deformed laminated heterolithic facies (Fig. 15d).

The gravelly facies assemblage is characterized by brownish to moderate grey coloration and contains poorly sorted litho-clasts of mudstone and sideritized material, occasionally with reworked bioclast fragments. The lithic particles exhibit rounded to elongated shapes and range in size from granules to pebbles. Erosional features are evident at the lower boundaries, while the upper boundaries appear sharp and irregular (Fig. 15e).

The integrated core photographs, BHI log and dipmeter data from certain sandstone intervals within the Sabaya–Maghrabi reservoir in the AB-6 well reveal several features. These include cross-laminated sandstone exhibiting intense oil staining (Fig. 16a), flaser-laminated sandy intervals, and alternating planar laminae of sand and mud (Fig. 16b). In addition, in the lower section of the Sabaya–Maghrabi reservoir, cross-laminated sandstone without any evidence of oil staining is observed, accompanied by some clay drapes (Fig. 16c). The dip angle of these laminations varies between c. 10° and 33° in the NW, NE, SE and west directions (Fig. 16).

The petrographical analyses were performed using thin sections. The quartz, feldspar and lithic ratios plotted on the sandstone triangular composition diagram reveal that most samples consist of kaolinitic subfeldspathic arenite and kaolinitic quartz arenite (Figs 16d and 17). In the examined thin sections (Fig. 17), kaolinitic subfeldspathic arenite is characterized by well-sorted, sub-angular to subrounded, highly to moderately cemented, silt-grade to fine-grained sand with strong compaction and grain–grain contact (Fig. 17c, d). Minor amounts of ferroan dolomite and microstylolites were also observed. Meanwhile, the kaolinitic quartz arenite lithofacies presents as moderate to well sorted, sub-angular to subrounded, highly cemented, and moderately to strongly compacted silt-grade to coarse-grained quartz with very few grains of plagioclase (Fig. 17a, b, e, f, k, l). Several types of compaction have been observed, such as long, point, concavo-convex and minor sutured grain contacts.

Certain intervals (i.e. at 1155.67 m) contain subfeldspathic wacke comprising silt-grade to fine-grained quartz and plagioclase, with poor to moderate sorting, sub-angular to subrounded grains, weak cementation, weak–moderate compaction, abundant pore-filling and grain-coating detrital clays (Fig. 17i, j). In addition, pyrite cement and grains of muscovite and kaolinite are observed (Fig. 17i, j). Meanwhile, the quartz wacke lithofacies appear as moderately sorted, sub-angular to subrounded grains, weakly cemented, weak to moderately compacted, silt-grade to fine-grained quartz with abundant pore-filling and grain-coating detrital clays (Fig. 17g, h). A significant range of measured porosity and permeability values has been observed in the Sabaya–Maghrabi reservoir (Fig. 18). Porosity values range from 3 to 25%, while horizontal and vertical permeabilities vary from 0.002 to 300 mD and from 0.002 to 200 mD, respectively (Fig. 18).

The geochemical data presented in Figure 5 highlight the B Member source rock as predominantly a good to very good source, characterized by kerogen types II to II/III (oil–gas prone). In addition, the T_max and %R_o values indicate that the B Member has matured and entered the main oil window (Fig. 5c, d). Figure 5 illustrates variations in the kerogen quality and maturity across different locations. Wells situated in the central part of the depocentre exhibit a high-quality source rock, primarily kerogen types II and II/III at certain depths, yielding mainly oil and a limited volume of gas (Hakimi et al. 2023). While samples from well ABSE-1 in the southeastern region mainly show kerogen types II/III to III (Fig. 5a). Furthermore, T_max and %R_o values indicate a higher thermal maturity of the B Member in wells AB-1, Kom-1 and Kom-2 compared to well ABSE-1 (Fig. 5c, d). Ali et al. (2024a) provided 2D thermal models for the Komombo Basin, indicating that the highest present-day temperatures are located in the deepest section of the depocentre. This suggests an extension of the B Member source rock into the gas window, with a predicted %R_o value of 1.4.

Moreover, the upper Maghrabi source rock is primarily identified as a good source rock with organic matter classified as type III (gas prone) (Fig. 6b). However, there is a notable decrease in both the quality and maturity of the upper Maghrabi Formation from the depocentre to the basin's shoulders (Fig. 6). For instance, well ABSE-1 exhibits maximum TOC and HI values of 5.94 wt% and 213 mgHC g⁻¹ TOC, respectively, which decrease northwestwards to 1.14 wt% and 115 mgHC g⁻¹ TOC in the Mem-1 well. This suggests significant organic richness and hydrocarbon generation potential in the depocentre compared to the flanks of the basin. Maturity data, including T_max and %R_o, indicate that the upper Maghrabi source rock is early mature to mature, reaching the oil window (Fig. 6c, d). However, it is considered non-productive due to its gas-prone nature and failure to reach the gas window.

The TOC and HI values of the Quseir Formation suggest that it serves mainly as a good to very good source rock, with organic matter classified as type II/III (oil–gas prone) to III (gas prone) (Fig. 7). Unlike the B Member and upper Maghrabi source rocks, the Quseir Formation exhibits consistent kerogen quality across both the basin's depocentre and flanks (Fig. 7). However, there is a notable variation in the maturity of the Quseir source rock. Wells in the depocentre (Kom-1, Kom-2 and AB-1) generally reveal a predominantly mature source rock, reaching the oil window, with maximum T_max and %R_o values of 448°C and 0.75, respectively. In contrast, wells located on the western flank (Kom-3) indicate a mainly immature source rock, with lower T_max and %R_o values (Fig. 7c, d). Analysis of samples from the Dakhla Formation indicates that it is a good to excellent source rock with a mixed kerogen type of II/III (oil–gas prone) to kerogen type III (gas prone) (Fig. 8). Kerogen quality is relatively higher in the depocentre area (wells ABSE-1, Kom-1, Kom-2 and AB-1) compared to the flanks (well Mem-1) of the Komombo Basin, although T_max values suggest similar thermal maturity throughout the basin. The Dakhla Formation is interpreted as a mainly immature to early mature source rock. The variation in TOC content and source-rock quality of sediments is controlled by biological productivity, lithology, and oxygenation of the water column and sediment (Jacobson 1991; McCarthy et al. 2011). In the Komombo Basin, the TOC values and quality of the studied source rocks are higher in the depocentre than the basin flanks, which is likely to be due to more shale-rich facies in this region.

The interpretation of the thermal maturity of the studied source rocks, based on available T_max and %R_o data, aligns with the findings of Ali et al. (2024a). They reported that the Pr/Ph (pristane/phytane), Pr/n-C₁₇ and Ph/n-C₁₈ ratios of the B Member source rock (1.17, 0.04 and 0.04, respectively) are lower compared to those of the Quseir (2.27, 0.74 and 0.34) and Dakhla (2.17, 1.05 and 0.59) source rocks, indicating higher maturity levels. In addition, analysis of recovered oil samples from three different reservoirs reveals an n-alkane distribution pattern and Pr/Ph, Pr/n-C₁₇ and Ph/n-C₁₈ ratios closely resembling those of the bitumen extracted from the B Member source rock. However, no significant correlation was observed between the source rocks of Dakhla and Quseir and the oils extracted from reservoirs.

The A Member reservoir's stratigraphic position is situated above a highly altered Proterozoic igneous rock. It lies beneath a pebbly sandstone facies (Sp) that has a sharp, erosive contact and lacks distinct sedimentary structures. This suggests possible in situ soil formation processes, with the altered igneous rock serving as the parent material. The presence of an overall fining-upward trend indicates a channel-fill sequence formed under such conditions. This vertical distribution and facies association, typically observed at the base of finer-grained overbank sediments, suggest deposition in a continental-influenced fluvial channel. Pebbles often found at the base of each fining-upward sequence are interpreted as channel-lag deposits (Fig. 11d). Moreover, the relatively high content of carbonaceous matter, occasionally with root-like traces, and the absence of bioturbation or fossil fragments, further support an overall non-marine, continental-influenced depositional environment.

The reservoir quality of the A Member of the Six Hills Formation varies depending on the type of facies assemblage and diagenesis. Facies such as Msc, Z, Zs and Sz, interpreted as overbank facies association, typically exhibit relatively poor reservoir quality, with measured porosities and permeabilities usually below 10% and 2 mD, respectively (Fig. 11c, d). The presence of abundant pore-filling argillaceous material significantly diminishes both vertical and horizontal permeabilities in these facies (Fig. 10a, i). However, the channel-fill facies (Sx and Sp) tend to have a mainly moderate reservoir quality, boasting an average porosity of 13% and permeability of 7 mD (Fig. 11b–d). However, the reservoir quality of these facies are compromised by factors such as relatively poor sorting and a moderate–high degree of compaction, along with a locally high content of detrital clays, all contributing to reduced reservoir quality (Fig. 10c, d, g, h).

The depositional environment of the C Member reservoir is interpreted as a middle–distal braidplain (Selim 2016). This reservoir comprises a mixture of mudstones, sandstones and some siltstone, aligning with the findings of Ali et al. (2020b), who presented a 3D facies model of the C Member reservoir, indicating c. 42% shale, 33% sandstone and 25% siltstone. Effective porosity calculations reveal that the quality of the C Member reservoir is better in the central part of the depocentre but diminishes southeastwards towards well ABSE-1 (Fig. 12). This observation is consistent with the findings of Ali et al. (2020b), who suggested that the C Member reservoir exhibits a fair reservoir quality based on 3D petrophysical models, aligning with recent reservoir classifications by Nabawy et al. (2018a, b). Generally, it displays intermediate porosity and low–intermediate permeability values, high net reservoir thickness, and low net pay thicknesses, potentially due to high water saturation values. Hydrocarbon saturation within this member is confined to the depocentre of the basin, corresponding with the overall increase in the porosity and permeability values (Ali et al. 2020b).

The sandstone reservoir intervals within the D–G members show significant thickness variations, mainly due to the impact of the growth normal faults (Ali et al. 2022a). These deposits are primarily proximal–mid braidplain sediments (Selim 2016). Several sand units within this interval exhibit high porosity values that range from 15 to 25% (Fig. 14), which aligns with previous findings (Othman et al. 2015; Senosy et al. 2020; Abdeen et al. 2021). For instance, Othman et al. (2015) utilized multi-attribute analysis and probabilistic neural network techniques to assess the Six Hill Formation E Member. Their findings indicated that this member serves as a promising reservoir, boasting an average porosity of 18% and a hydrocarbon saturation of 48%. Moreover, Senosy et al. (2020) identified two hydrocarbon-bearing zones within the D and E members of the Six Hills Formation, observed in wells AB-14 and AB-4, situated in the depocentre region of the Komombo Basin. The D Member reservoir shows an average porosity of 17% with a water saturation of 36%, whereas the E Member reservoir exhibits a slightly lower quality, with an average porosity of 14% and a water saturation of 57%. Another promising reservoir interval within the F Member of Six Hills Formation was identified by Abdeen et al. (2021), with an effective porosity of 17% and water saturation of 50%.

In the Sabaya–Maghrabi reservoir, grain-size analysis of the sandstone facies assemblage based on thin-section examination revealed that it ranged from silt-grade to coarse-grained subfeldspathic and quartz arenite sandstones. Porosity and permeability plots show a clear linear relationship between porosity and both horizontal and vertical permeability, as well as a strong correlation between horizontal and vertical permeability values. The siltstone facies exhibit very low reservoir quality, with porosity values ranging from 3 to 10%, and horizontal and vertical permeabilities typically less than 1 mD (Fig. 18). In contrast, the sandstone facies of the Sabaya–Maghrabi reservoir generally exhibit agood to very good reservoir quality, with most samples showing porosity values exceeding 10% and permeabilities ranging from low to high, averaging around 10 mD (Fig. 18). These findings align with Ali et al. (2020a), who constructed a 3D static model of the Albian–Cenomanian reservoir that suggests it comprises c. 45% sandstone, 32% siltstone and 23% shale. Their petrophysical modelling indicates a good to very good reservoir quality, characterized by medium–high porosity and permeability values, albeit with high water saturation. However, hydrocarbon saturation is predominantly limited to specific parts within the basin, particularly in the central area and towards the SE direction (Ali et al. 2020a).

The increasing interest in black shale in Egypt in recent years is primarily driven by its potential as a natural, unconventional energy source for the future (El Kammar 2015). High organic content black shale deposits are widespread throughout Egypt, particularly in the Late Cretaceous and Paleogene sediments. These deposits include the Quseir, Duwi, Dakhla and Esna formations (El Kammar 2015). In the Komombo Basin, the Dakhla and Quseir formations are considered promising unconventional reservoirs. They feature high TOC values and predominantly comprise Kerogen type II/III, with some samples showing Kerogen type II (Figs 2, 7 and 8). The Dakhla Formation exhibits a higher organic content compared to the Quseir Formation in the basin. The Dakhla Formation boasts a maximum TOC value of 8.33 wt% and an average value of 2 wt%. In contrast, the Quseir Formation has a maximum TOC value of 4.33 wt% and an average value of 1.5 wt%. The maturity data indicate that some samples from both source rocks have reached the early stage of the oil window (Figs 7 and 8). Conversely, the black shales of the Dakhla and Quseir formations in Gebel Duwi, in the Quseir area of the Eastern Desert, are considered oil shale and gas shale reservoirs, respectively. They exhibit even higher TOC values than those in the Komombo Basin (El Kammar 2015). In the Komombo Basin, further petrophysical and geomechanical analyses are needed to fully investigate the characteristics of these unconventional reservoirs.

Several shale units within the lithostratigraphic section of the Komombo Basin serve as potential seal rocks. These include the B Member of the Six Hills Formation, the Aptian shale of the Abu Ballas Formation, the upper Maghrabi Formation and the Taref Formation. The B Member acts as an excellent sealing rock for the A Member reservoir. It is distinguished by a thick shale layer (>60 m) exhibiting strong lateral continuity (Fig. 2). The mudstones within the B Member display minimal porosity, typically ranging from 0 to 5% (Fig. 12). The Abu Ballas Formation, a prominent marker bed within the Komombo Basin, spans the entire basin and comprises c. 40 m of mudstones. This formation serves as a reliable sealing rock for the upper sand units of the D–G members. The extensive lateral continuity and substantial thickness of both the upper Maghrabi and Taref formations indicate the existence of a potential cap rock for the productive Sabaya–Maghrabi reservoir (Fig. 2). Intra-formational shales are also found within the C Member and the D–G members of the Six Hills and Sabaya–Maghrabi reservoirs (Figs 2, 12 and 14). These shales could be potential seal rocks; they vary in thickness, ranging from a few metres to up to 12 m, yet maintain relatively consistent continuity and exhibit negligible porosity values (0–5%). The extensive sedimentation in the central basin throughout the Cretaceous and Pliocene has supplied ample overburden sediments necessary for the sealing potential of the underlying reservoirs (Fig. 2). Ali et al. (2024a) suggested that normal faults play a significant role in the hydrocarbon system of the Komombo Basin by forming traps, controlling migration paths and affecting seal integrity. They observed that unsealed faults act as pathways for hydrocarbons, and reactivation can compromise trap integrity and lead to potential leaks. To evaluate the risk for fault seal failure further, an in-depth geomechanical and geological analysis is necessary, which is currently not possible with the available data. Additional geological and petrophysical data are required to conduct a meaningful quantitative assessment with manageable uncertainties.

A comprehensive integration of geophysical and geological data has been utilized to assess the petroleum system elements of the Komombo Basin. From the available geochemical data, four distinct source rocks have been recognized: the B Member of Six Hills Formation and the upper Maghrabi, Quseir and Dakhla formations. The B Member, predominantly located in the depocentre area, shows TOC values ranging from 0.5 to 3.74 wt% and HI values between 118 and 365 mgHC g⁻¹ TOC. It is considered a good to very good source rock, characterized by kerogen types II to II/III, and has reached the main oil window. The upper Maghrabi Formation exhibits TOC values ranging from 0.51 to 5.94 wt% and HI values from 33 to 213 mgHC g⁻¹ TOC, while the Quseir Formation shows variable TOC (0.75–4.92 wt%) and HI (14–225 mgHC g⁻¹ TOC) values. The upper Maghrabi and Quseir formations are classified as good and good to very good source rocks, containing predominantly type III and type II/III organic matter, respectively. They are immature to mature source rock, reaching the early oil window. The Dakhla Formation displays TOC values ranging from 0.56 to 8.33%, and HI values between 17 and 285 mgHC g⁻¹ TOC. It is identified as a good to excellent source rock with a mixed kerogen type of II/III to type III, mainly immature to early mature. Variations in the kerogen quality and maturity are observed across different locations, with wells in the depocentre exhibiting higher quality and maturity compared to those in the shoulders of the basin.

The Komombo Basin contains four reservoir units: the A Member, C Member, sandstone units within the D–G members of the Six Hills Formation, and the Sabaya–Maghrabi reservoir. The reservoir quality across these units varies, influenced by facies assemblage and diagenesis, including cementation and compaction. The A Member's channel deposits typically display moderate reservoir quality, boasting an average porosity of 13% and permeability of 7 mD. Conversely, the C Member reservoir comprises thick sandstones with good porosity values, categorized as fair reservoir quality due to a high clay content. Sandstone intervals within the Barremian section hold promise as reservoirs, showcasing high porosity values that range from 15 to 25%. In addition, hydrocarbon-bearing zones have been documented within this interval, located in the depocentre of the basin. In contrast, the sandstone facies of the Sabaya and Maghrabi formations generally exhibit a good to very good reservoir quality, with high porosity values (>10%) and permeabilities ranging from low to high, averaging around 10 mD. In the Komombo Basin, two unconventional reservoirs have been identified: the Dakhla Formation and the Quseir Formation. The B Member of the Six Hills Formation and the Abu Ballas, upper Maghrabi, and Taref formations have been identified as potential seal rocks, in addition to shales within the reservoir units. Faults are prevalent structural traps in the basin, yet the criteria for pinchout and wedging phenomena have not been thoroughly evaluated.

We are grateful to the Ganope Company for providing the data used in this study and for their approval to publish the paper. We would like to thank the reviewers for their valuable comments and constructive modifications that greatly enhanced the manuscript.

MA: conceptualization (lead), data curation (lead), investigation (equal), methodology (lead), resources (equal), software (lead), validation (lead), visualization (lead), writing – original draft (lead); MYA: investigation (equal), project administration (lead), resources (equal), supervision (lead), validation (supporting), writing – review & editing (equal); AA: data curation (equal), resources (equal), supervision (equal), writing – review & editing (equal).

This work was funded by the Khalifa University of Science and Technology under Award No. 8474000621 (grant awarded to M. Ali).

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.

The data are restricted, and the authors have no permission to share the data used.