Introduction

The Komombo Basin is situated in the southern Western Desert, approximately 65 km northwest of Aswan (Fig. 1a). This basin is considered a half-graben (Fig. 2), intracontinental rift basin; it is considered the only producing basin in southern Egypt (Ali et al. 2017a). Bosworth et al. (2008) mentioned that the stress regime created in North and Central Africa associated with the creation of the South Atlantic was responsible for the creation of the Komombo Basin. This basin is bounded by a major normal fault striking NW-SE that is situated to the NE side of the Komombo Basin and down-thrown towards the southwest. Many minor normal faults are also characterized by the same NW-SE direction (Fig. 1b). The Komombo Basin contains approximately 13100 ft. of sediments (Fig. 3), mainly clastic rocks (shale and sandstone) with some carbonate deposits (Ziegler 1992).

Fig. 1
figure 1

a Landsat map showing the study area within Gebel Duwi and Komombo Basin, southern Egypt (Ali et al. 2017b). b, c Base maps showing the location of the used boreholes. d Geologic map shows the stratigraphic units of the Gebel Duwi (modified after Khalil and McClay (2002))

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Fig. 2
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a Uninterpreted NE-SW 2D seismic section (05-01-Cf77-08) crossing the Komombo basin, Upper Egypt and b interpreted NE-SW 2D seismic section showing the half graben basin and the main seismic horizons in the study area (Ali et al. 2019)

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Fig. 3
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Stratigraphic chart of the Komombo Basin showing that the stratigraphic succession is representative of non-marine and shallow marine deposits are during Cretaceous (Berriasian-Maastrichtian) (Selim 2016)

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The main objective of the current research is to (1) identify the geochemical characteristics of the Dakhla source rock in the Komombo Basin; (2) compare the results for the Komombo area to the geochemical characteristics for the Dakhla source rock in Gebel Duwi, the Qusier area discussed by El-Kammar (2015), El-Shafeiy et al. (2017), and Fathy et al. (2018); and (3) explain the main reasons for the characteristic variations in the Dakhla source rock in the two areas. Rock-Eval pyrolysis and total organic carbon (TOC) data for the Dakhla source rock in the Komombo area, as well as geochemical data for the same source rock at Gebel Duwi in the Qusier area are examined.

Stratigraphy

The stratigraphic column of the Komombo Basin is representative of non-marine and shallow marine sequences deposited during the Cretaceous period (Abdelhady et al. 2016). The stratigraphic succession is composed of seven formations from bottom to top, and these are the Six Hills, Abu Ballas, Sabaya, Maghrabi, Taref, Quseir, and Dakhla Formations (Fig. 3). In this regard, Selim (2016) indicated that the Dakhla Formation is representative of an open marine system. This formation is mainly composed of grey to dark grey, altered laminated shale with some siltstone and sandstone interbeds (Fig. 4a, b). Awad and Ghobrial (1965) classified this formation into 3 members from top to base: Kharga shale member, Baris Oyster mudstone member, and Mawhoob shale member, with total thickness at the type section of approximately 700 ft.

Fig. 4
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Examples of the Dakhla open marine deposits in Komombo Basin, AB-5 well (Selim 2016)

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The areal distribution of the Dakhla Formation is widespread across the central and southern areas of the Eastern and Western Deserts and along the Red Sea coast in down-thrown faulted blocks. In the north, the facies changes to limestone and chalks of the Khoman and Sudr formations. To the south of Kharga, the Paleocene is completely or partially replaced by Paleocene limestone (Ammonite Hill member) (Barthel and Herrmann-Degen 1981).

The stratigraphic column of the Komombo Basin contains several shale intervals. According to Ali et al. (2018), the Hauterivian-Early Barremian shale represents the main source rock in the Komombo Basin. Despite that, the Campanian-Maastrichtian Dakhla Formation (Abu El Ella 2006, 2011) consists mainly of argillaceous limestone, calcareous shale, and shale of marine origin with high-organic contents; therefore, the Dakhla Formation is a promising potential source rock. The thickness of the Dakhla Formation in Komombo ranges between 400 ft in the flank and 800 ft in the depocenter of the basin (Ali 2017). On the other hand, Gebel Duwi is located in the Qusier area of the Eastern Desert, Egypt (Fig. 1c). A detailed stratigraphic description of Gabel Duwi by El-Kammar (2015) mentioned that the maximum thickness of the Dakhla Formation there is 540 ft. El-Kammar et al. (2013) supposed that the Dakhla Formation is Maastrichtian-Early Paleocene and is representative of shallow to deep marine deposits because it contains planktonic and nanoplanktonic foraminifera, dinoflagellates, and palynomorphs. According to Fathy et al. (2018), the CaCO3 content and the carbonate/siliciclastic ratio indicate that the Dakhla Formation oil shales were deposited during a relative sea-level rise in a deep marine setting under a warm/wet climate with an elevated chemical weathering intensity, and these shales consist of two members (Hamama and Beida members) of the Maastrichtian-Paleocene age.

Data and methods

Fifty-nine ditch samples were analyzed from three wells in various parts of the Komombo Basin to identify the geochemical characteristics of the Dakhla source rock. The Kom-3 well is located on the western flank, and wells AB-1 and ABSE-1 are located in the depocenter of the Komombo Basin (Figs. 1b, c and 2). The ditch samples were analyzed by Vinci Technologies Rock-Eval 6 Turbo apparatus and a Leco SC 632 instrument (for more details on this method, see Espitalié et al. (1977) and Peters et al. (2005)). The geochemical analyses of the selected samples were performed at the Stratochem Laboratory, Cairo, Egypt. In addition, previously published data from 230 ditch and core samples that were previously published (El-Kammar 2015; El-Shafeiy et al. 2017; Fathy et al. 2018) for Gebel Duwi in the Qusier area were used for comparison purposes.

The interpretation of source rock parameters and the Rock-Eval pyrolysis data method are discussed in detail by Espitalié (1986), Peters (1986), and Peters and Cassa (1994). The evaluated parameters are S1, S2, S3, the HI, the OI, and the productivity index (PI). On the other side, S1 measures the amount of free hydrocarbons that can be volatilized out of the rock without cracking the kerogen (mg HC/g rock); S1 increases at the expense of S2 with maturity. S2 measures the hydrocarbon yield from cracking of kerogen (mg HC/g rock) and is a more realistic measure of source rock potential than TOC because TOC includes “dead carbon” incapable of generating petroleum (Peters and Cassa 1994). S3 represents the amount of generated CO2, and Tmax (°C) represents the temperature at maximum generation of S2. The HI [HI = (S2/TOC) × 100, mg HC/g TOC] is proportional to the amount of hydrogen in the kerogen and thus indicates the potential of the rock to generate oil. The OI [OI = (S3/TOC) × 100, mg CO2/g TOC] is related to the amount of oxygen in the kerogen. The production or productivity index [PI = S1/(S1 + S2)] gradually increases with depth for fine-grained rocks as thermally labile components in the kerogen (S2) are converted to free hydrocarbons (S1).

Results and Discussion

Organic richness and Rock-Eval Pyrolysis data

The collected and analyzed ditch samples of the Dakhla Formation in the Komombo Basin range from 1900–2700 ft in well AB-1, 1300–2100 ft in well ABSE-1, and 1420–1810 ft in well Kom-3. The organic richness is determined by TOC and S1 + S2 (Waples 1979 and Peters 1986). The TOC and Rock-Eval pyrolysis data of the Dakhla Formation in the Komombo Basin are summarized in Figs. 6, 7, and 8. The TOC values of the analyzed ditch samples range between 0.46 and 2.66 wt.% (avg. 1.58 wt.%), which is consistent with fair to good source rock for hydrocarbon generation. If S1 + S2 yields are more than 6 mg HC/g rock, then the material represents good to excellent source rock, and values less than 6 mg HC/g rock represent poor to fair source rock (Peters 1986; Peters and Cassa 1994). The S1 + S2 yields range from 1.71 to 6.67 (mg HC/g rock). These data indicate poor to good source rock and are proportioned with TOC values (Figs. 5, 6, and 7).

Fig. 5
figure 5

Lithological and geochemical logs of the Dakhla source rock in AB-1 well, Komombo Basin, showing Rock-Eval pyrolysis data as well as TOC and % Ro values

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Fig. 6
figure 6

Lithological and geochemical logs of the Dakhla source rock in ABSE-1 well, Komombo Basin, showing Rock-Eval pyrolysis data as well as TOC and % Ro values

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Fig. 7
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Lithological and geochemical logs of the Dakhla source rock in Kom-3 well, Komombo Basin, showing Rock-Eval pyrolysis data as well as TOC and % Ro values

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S1 values in wells AB-1 and ABSE-1 are zero, thus they may indicate that the Dakhla source rock in the Komombo Basin has not reached the mature stage. In contrast, the S1 values in well Kom-3 range from 0.13 to 1.58 (mg HC/g rock); however, well Kom-3 lies in the western flank of the Komombo Basin, not in the depocenter like wells AB-1 and ABSE-1. The S1 yields in well Kom-3 may therefore be concluded to mark oil that migrated from the Hauterivian-early Barremian B member, which represents the main source rock in the Komombo Basin (Ali et al. 2018).

According to El-Kammar (2015), the TOC values of 70 analyzed samples of the Dakhla source rock collected from a tunnel in Gebel Duwi range from 2.03 to 12.07 wt.%, (avg. 4.51 wt.%). The TOC values indicate that the source rock has elevated quantities of organic matter, which is representative of good to excellent source rock. These samples display S1 values ranging from 0.18 to 2.39 mg HC/g rock (avg. 0.58), and S2 yields are in the range of 10–112 mg HC/g rock (avg. 34), indicating good to excellent source rock (El-Kammar 2015; Fathy et al. 2018). El-Shafeiy et al. (2017) interpreted organic-rich core samples of the Dakhla Formation at Gebel Duwi in the Qusier area, which were drilled by the Egyptian Mineral Resources Authority (EMRA); TOC contents range from 2 to 14 wt.%, (avg. 6 wt.%) for the Hamama member and TOC values average 2.4, 4.3, and 2.1 wt.% for the lower, middle, and upper parts of the Bedia member, respectively.

Overall, the source rock quality of the Dakhla Formation varies from fair to good source rock in the Komombo Basin, west of the River Nile (TOC 0.46-2.66 wt.% and S1 + S2 0.62–7.17 mg HC/g rock) and good to excellent source rock in the Qusier area, east of the River Nile (TOC 2.1–14 wt.% and S1 + S2 10.52–58.5 mg HC/g rock). This, in turn, indicates that the productivity (the amount and concentration of organic matter in the sedimentary basin) of the Dakhla Fm. in Gebel Duwi is higher than that in the Komombo Basin because productivity depends on many factors, such as nutrient availability, temperature, light intensity, and general water chemistry (Demaison and Moore 1980; Emerson 1985). Alternatively, the preservation of organic matter (OM) may be another reason, where the resistance of OM to degradation is affected by three factors: (a) the type of OM deposited; (b) the concentration and nature of the oxidizing agent; and (c) the sediment accumulation rate (Emerson 1985). Therefore, the authors suppose that the OM of the Dakhla Fm. in Gebel Duwi experienced excellent survival and was deposited where anoxia developed in an aqueous environment with high rates of sedimentation because the source rock is oil-prone. On the other hand, the OM of the Dakhla Fm. in the Komombo Basin was deposited in an oxic environment with high sedimentation rates because the source rock is gas-prone.

Kerogen Type

The kerogen is classified into three major categories: liptinite (exinite), vitrinite, and inertinite, based on physical properties (Stach et al. 1982). Liptinite–exinite components, which are derived from high-lipid organic materials such as pollens, cuticles, spores, phytoplanktonic algae and resins, which are related to Types I and II kerogen (highly oil-prone). Vitrinite is derived from lignified tissues produced from land plants of terrestrial origin, and it is predominately Type III kerogen (gas-prone). Inertinite represents oxidized organic material with high-carbon content and shows no hydrocarbon potential (Stach et al. 1982; Cornford 1984; Hunt 1996; Miles 1989).

The visual kerogen compositions of the selected samples from wells AB-1 and ABSE-1 (Table 1) are mostly dominated by OM high in undifferentiated and amorphous unstructured lipids (20–80%) and low to medium in vitrinite and recycled vitrinite (15–50%), with small inertinite contents (5–15%). The lipid OM is predominantly amorphous with some structure and terrestrial material. Structured lipids consist mostly of sporinite, suberinite, resinite, and cutinite, thus suggesting a terrestrial origin for most samples (Abdelhady et al. 2016). Therefore, the expected kerogen type of the Dakhla source rock from the coal petrography is Type III (Table 1).

Table 1 AB-1 and ABSE-1 wells kerogen composition
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The HI (mg HC/g TOC) is one of the most commonly used parameters to determine that kerogen type (Espitalié et al. 1977). Peters and Cassa (1994) and Petersen and Nytoft (2006) supposed that Type I kerogen (oil-prone) is associated with high HI values > 600 mg HC/g TOC, in contrast with Type II (oil- and gas-prone) with HI values of 350 to 600 mg HC/g TOC; Type III kerogen (gas-prone) is identified by HI values from 50 to 200. Type IV kerogen is associated with low HI less than 50 (Tissot et al. 1974; Demaison et al. 1983). The HI values of the Dakhla source rock samples in the Komombo Basin range between 40 and 285 (avg. 115 mg HC/g TOC), indicating Type III kerogen. The number of analyzed ditch samples showing Type III kerogen (HI < 200 mg HC/g TOC) was 56 out of a total of 59 samples. The Dakhla Formation is deemed to be Type III kerogen based on the S2 and TOC diagram (Langford and Blanc-Valleron 1990) (Fig. 8). The HI vs. Tmax, HI vs. OI and HI vs. %Ro plots indicate that the kerogen type of the Dakhla source rock is Type III (gas-prone) (Figs. 9, 10, and 11, respectively). Therefore, all plotted data show that the Dakhla source rock of the Komombo Basin is Type III kerogen, and the Dakhla Formation’s OM is mostly of terrestrial origin and thus deemed gas-prone.

Fig. 8
figure 8

Plot of TOC vs S2 values shows Type III kerogen for the Dakhla source rock samples in Komombo Basin (Langford and Blanc-Valleron 1990)

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Fig. 9
figure 9

Plot of Tmax versus HI shows that the Dakhla Fm. in the Komombo Basin is Type III kerogen and it is immature to early mature stage for oil generation (Espitalié 1986)

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Fig. 10
figure 10

HI versus OI cross plots indicate that most of the Dakhla Formation samples in Komombo Basin belong to kerogen Type III (van Krevelen 1961)

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Fig. 11
figure 11

Plot of Ro% versus HI shows that the Dakhla Fm. in the Komombo Basin is Type III kerogen and it is immature to early mature stage for oil generation (Espitalié 1986)

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According to El-Kammar (2015)), the analyzed samples of the Dakhla source rock in Gebel Duwi show HI values ranging from 381 to 1023 mg HC/g TOC (avg. 711 mg HC/g TOC). Fifty samples among 64 analyzed rock samples show Type I kerogen, where HI values are more than 600 mg HC/g TOC. Figure 12 confirms the existence of Types I and I/II kerogen, where HI and OI values are plotted on a modified van Krevelen diagram. El-Shafeiy et al. (2017) confirmed that the kerogen type of the Dakhla Formation is Type II with the exception of the lowermost and middle Hamama member and the middle part of the Beida member that contains Type I kerogen. Therefore, the OM of the Dakhla source rock is mainly of marine origin and thus considered oil-prone with rare gas.

Fig. 12
figure 12

HI versus OI cross plots indicate that most of the Dakhla Formation samples at Gebel Duwi belong to kerogen I and I/II (van Krevelen 1961)

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The quality of the Dakhla source rock can be concluded to vary from Type III kerogen in the Komombo Basin to Type I/II kerogen in Gebel Duwi because the OM of the Dakhla source rock in the Komombo Basin is mostly terrestrial in origin, but it is mostly of marine in Gebel Duwi. We believe that the main reason for this situation is that the OM of the Komombo Basin was derived from sources external to the water body (allochthonous) and has high amounts of land plant remains. On the other hand, the OM was produced within the immediate water body (autochthonous) at Gebel Duwi and has high-lipid organic materials such as algae, leaves, spores, and pollen.

Thermal maturity

Tmax and vitrinite reflectance (%Ro) data are used to evaluate the thermal maturity level of the Dakhla Formation. Tmax values less than 435 °C indicate that the kerogen is immature, whereas values greater than 460 °C indicate the end of the oil window and the start of the wet gas zone (Espitalié et al. 1977). Based Tmax majority of the Dakhla Formation in the Komombo Basin is immature to early mature (Fig. 9), with Tmax values ranging between 422 and 444 °C. Furthermore, the %Ro values are widely used to establish the level of thermal maturity of source rocks (Dow 1977; Waples et al. 1992). The %Ro is the most reliable maturity parameter for calibrating and measuring the thermal maturity of organic matter (Grassmann et al. 2005). The %Ro values for the Dakhla source rock in the Komombo Basin are in the range from 0.43 to 0.78%Ro. In this regard, Dow (1977) and Senftle and Landis (1991) suggested that when the %Ro values are in a range of 0.6 to 1.35, the source rock is mature. Thus, most of the analyzed ditch samples from the Dakhla source rock in the Komombo area are interpreted to be immature to early mature for hydrocarbon generation (Fig. 11). Figure 13 shows that the %Ro values in well Kom-3 are positively related to depth and show increased maturity with increasing burial depth. Based on this maturity profile, the top of the oil window (defined by 0.6%Ro) should be encountered in the middle of the Campanian-Maastrichtian section at approximately 1300 ft. This result means that the Campanian-Maastrichtian Dakhla Formation consists of immature to early mature source rocks. The Tmax values of the same source rocks in Gebel Duwi range between 412 and 435 °C, indicating that most of the analyzed rock samples are in the immature to early mature stages.

Fig. 13
figure 13

Vitrinite reflectance log of Kom-3 well, showing a positive relationship with depth and the top of the oil window is at approximately 1300 ft

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Conclusions

The results for rock samples that were collected and analyzed to evaluate the organic geochemical characteristics of the Dakhla source rock in the Komombo Basin and at Gebel Duwi in the Qusier area indicate that the quality of the Dakhla source rock varies from fair to good in the Komombo Basin and from good to excellent at Gebel Duwi. The source rock quality varies from Type III kerogen in the Komombo Basin to Type I/II kerogen at Gebel Duwi. The OM of the Dakhla Formation in the Komombo Basin is mostly terrestrial in origin, while the OM is mainly of marine origin at Gebel Duwi. The Type III kerogen in the Komombo Basin is considered gas-prone, while the Types I/II kerogens at Gebel Duwi are considered oil-prone with rare gas. Based on the measured %Ro and Tmax values, the Dakhla Formation is mostly in the immature to early mature stage for hydrocarbon generation in both areas, with the Tmax values in the Komombo Basin and Gebel Duwi ranging from 422–444 °C and 412–435 °C, respectively. The %Ro values vary between 0.43 and 0.78 in the Komombo Basin. According to the hydrocarbon potential and maturity, the Dakhla source rock can be concluded not to have reached the oil and gas generation window in either area.