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Article

Investigating Attributes of Oil Source Rocks by Combining Geochemical Approaches and Basin Modelling (Central Gulf of Suez, Egypt)

by
Moataz Barakat
1,
Mohamed Reda
2,3,
Dimitra E. Gamvroula
4,
Robert Ondrak
5 and
Dimitrios E. Alexakis
4,*
1
Geology Department, Faculty of Science, Tanta University, Tanta 31527, Egypt
2
Geology Department, Faculty of Science, Al-Azhar University, Cairo P.O. Box 11884, Egypt
3
Department of Petroleum Engineering, College of Engineering, Almaaqal University, Basrah 61014, Iraq
4
Laboratory of Geoenvironmental Science and Environmental Quality Assurance, Department of Civil Engineering, School of Engineering, University of West Attica, 250 Thivon & P. Ralli Str., 12241 Athens, Greece
5
Section Organic Geochemistry, GFZ Helmholtz Centre for Geosciences, Tele Gräfenberg, 14473 Potsdam, Germany
*
Author to whom correspondence should be addressed.
Resources 2025, 14(7), 114; https://doi.org/10.3390/resources14070114
Submission received: 31 May 2025 / Revised: 6 July 2025 / Accepted: 8 July 2025 / Published: 16 July 2025
Browse Figures
Versions Notes

Abstract

The present study focused on the Upper Cretaceous to Middle Miocene sequence in the Central Gulf of Suez, Egypt. The Upper Cretaceous to Middle Miocene sequence in the October field is thick and deeply buried, consisting mainly of brown limestone, chalk limestone, and reefal limestone intercalated with clastic shale. This study integrated various datasets, including total organic carbon (TOC), Rock-Eval pyrolysis, visual kerogen examination, vitrinite reflectance (%Ro), and bottom-hole temperature measurements. The main objective of this study is to delineate the source rock characteristics of these strata regarding organic richness, thermal maturity, kerogen type, timing of hydrocarbon transformation and generation. The Upper Cretaceous Brown Limestone Formation is represented by 135 samples from four wells and is considered to be a fair to excellent source rock, primarily containing type I and II kerogen. It is immature to early mature, generating oil with a low to intermediate level of hydrocarbon conversion. The Eocene Thebes Formation is represented by 105 samples from six wells and is considered to be a good to fair oil source rock with some potential for gas, primarily containing type II and II/III kerogen. Most samples are immature with a low level of hydrocarbon conversion while few are mature having an intermediate degree of hydrocarbon conversion. The Middle Miocene Lower Rudeis Formation is represented by 8 samples from two wells and considered to be a fair but immature source rock, primarily containing type III kerogen with a low level of conversion representing a potential source for gas. The Middle Miocene Belayim Formation is represented by 29 samples from three wells and is considered to be a poor to good source rock, primarily containing kerogen type II and III. Most samples are immature with a low level of hydrocarbon conversion while few are mature having an intermediate degree of hydrocarbon conversion. 1D basin model A-5 well shows that the Upper Cretaceous Brown Limestone source rock entered the early oil window at 39 Ma, progressed to the main oil window by 13 Ma, and remains in this stage today. The Eocene Thebes source rock began generating hydrocarbons at 21.3 Ma, advanced to the main oil window at 11 Ma, and has been in the late oil window since 1.6 Ma. The Middle Miocene Lower Rudeis source rock entered the early oil window at 12.6 Ma, transitioned to the main oil window at 5.7 Ma, where it remains active. In contrast, the Middle Miocene Belayim source rock has not yet reached the early oil window and remains immature, with values ranging from 0.00 to 0.55 % Ro. The transformation ratio plot shows that the Brown Limestone Formation began transforming into the Upper Cretaceous (73 Ma), reaching 29.84% by the Miocene (14.3 Ma). The Thebes Formation initiated transformation in the Late Eocene (52.3 Ma) and reached 6.42% by 16.4 Ma. The Lower Rudeis Formation began in the Middle Miocene (18.7 Ma), reaching 3.59% by 9.2 Ma. The Belayim Formation started its transformation at 11.2 Ma, reaching 0.63% by 6.8 Ma.

1. Introduction

The Gulf of Suez sedimentary rift basin, spanning approximately 19,000 km2, is Africa’s most productive hydrocarbon basin. It is bordered on both sides by extensive NW-striking normal fault zones that shape half-grabens [1]. The basin formed due to the Arabian plate’s separation from the African plate. It contains over eighty hydrocarbon fields, established through 240 discoveries from thousands of exploration wells, with findings amounting to up to 1 million barrels of oil in Precambrian to Quaternary reservoirs [2]. This makes it highly significant to Egypt’s upstream industries [3,4]. The Gulf of Suez’s structural complexity presents opportunities for new plays and previously untapped hydrocarbon pools, which can be accessed using advanced technologies such as seismic imaging and complex drilling techniques.
Source rock evaluation and basin modelling are crucial for enhancing subsurface understanding of potential source rock formations and the associated reservoir intervals they may charge. This enhanced understanding directly influences future field development strategies and well placement decisions [5,6,7,8].
The offshore October oil field, Egypt’s third-largest oil field, is situated in the central offshore region of the Gulf of Suez, approximately 135 km southeast of Suez City. Positioned between latitudes 28°46′40″ and 28°57′10″ N and longitudes 32°57′33″ and 33°10′00″ E (Figure 1), the October field lies within a NW-SE trending fault block that extends 30 km from Gebel Nazzazat through the offshore central Gulf of Suez [9,10]. Production at the field commenced in 1977, with peak output reaching 136,000 barrels of oil per day (BOPD) [11,12].
This study focuses on the source rock formations, ranging from the Upper Cretaceous to the Middle Miocene, within the October field in the Central Gulf of Suez Basin. Key source rocks in this region include the El Egma Group, featuring the Upper Senonian Brown Limestone and the Eocene Thebes Formation, as well as the Middle Miocene Lower Rudeis Formation (Gharandal Group) and the Belayim Formation of the Ras Maalab Group [13,14,15,16,17].
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Figure 1. (a) A simplified structural setting of the Gulf of Suez rift showing the main structures on both sides of the Gulf of Suez [18], showing the location of the October field in the central province. ZAZ (Zaafarana Accommodation Zone), MAZ (Morgan Accommodation Zone), (b) Base map showing the selected well locations for the analysis of source rocks.
Figure 1. (a) A simplified structural setting of the Gulf of Suez rift showing the main structures on both sides of the Gulf of Suez [18], showing the location of the October field in the central province. ZAZ (Zaafarana Accommodation Zone), MAZ (Morgan Accommodation Zone), (b) Base map showing the selected well locations for the analysis of source rocks.
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Extensive research on source rock evaluation and 1D basin modelling in the October field has been well-documented [19,20,21,22,23]. El-Ghamri et al. [24] explored the aspects of oil generation and migration, while Sercombe et al. [25,26] focused on the structural geology and reservoir modelling of the field. Many researchers [15,27] provided detailed characterisation of source rock properties and conducted petroleum system analysis. Additionally, Kassem et al. [28] examined the organic geochemical and isotopic data of the Cenomanian–Turonian shales and limestones, correlating these sediments with the Oceanic Anoxic Event 2 (OAE2), which led to the formation of organic-rich intervals.
Additional research on the Nezzazat Group in the Central and Southern Gulf of Suez has covered various aspects, including reservoir geometry analysis [29,30,31], the impact of glauconite on log responses [32], lithology assessment [33], and petrophysical rock typing of the Matulla Formation [34,35].
In this study, we integrated Rock-Eval pyrolysis, well log analysis, and basin modelling techniques to evaluate the source rocks of the Upper Cretaceous Brown Limestone, the Eocene Thebes, and the Middle Miocene Lower Rudeis and Belayim formations, aiming to delineate the primary petroleum system in the October oil field. The main aims are: (i) to investigate the organic richness and thermal maturity of the source rocks, (ii) to utilize well log analysis as an effective tool for assessing maturity levels, and (iii) to develop a 1D basin model to characterize the various petroleum systems within the study area.

2. General Geology

2.1. Structure

The rift of the Gulf of Suez originated from lithospheric stretching in the Oligocene, followed by extension-driven subsidence that began in the Early Miocene. This rifting phase involved significant tectonic subsidence and magmatic activity during the Oligo-Miocene period [36]. The first phase of post-rift, primarily characterised by thermal subsidence with minor reactivation of pre-existing faults (14.2–5.2 Ma), was followed by the deposition of the Belayim, South Gharib, and Zeit formations [37]. The second phase (5.2–0 Ma) was characterised by lithospheric cooling, which created additional accommodation space for the deposition of the Post-Zeit Formation [37]. Basin-wide unconformities formed in response to regional tectonic adjustments associated with the multiple rifting phases of the Gulf of Suez [38,39].
The Gulf of Suez is characterized by typical structures such as horsts, grabens, and half-grabens, with faults trending NW–SE (Clysmic faults) orthogonal to the main extension direction [34,35,36,37,38,39,40,41,42]. In the October oil field, four dominant fault trends are observed: NNW–SSE (the oldest trend), NE–SW (associated with the Syrian Arc system), NW–SE (Clysmic trend), and NNE–SSW (Aqaba trend) [43]. Relay ramps frequently occur along the NW-SE trending border faults (e.g., in the Hammam Faraun, El-Qaa, or Abu Durba fault blocks). Trap formation (Figure 1) primarily occurred during the early rifting phase when rapid subsidence affected pre-rift units [44]. The Clysmic fault system and cross-cutting elements subdivide the October area into distinct horst and graben blocks, each with its unique reservoir characteristics [45].

2.2. Stratigraphy

The sedimentary succession in the October field, similar to other Gulf of Suez oil fields (Figure 2), is structurally controlled and is typically divided into three major mega-sequences [46]. The stratigraphy of the central Belayim Province, particularly in the October field, has been extensively studied through cores from oil wells and nearby outcrops [47,48,49,50]. The stratigraphic sequence in the October field is about 3000 m thick, compared to over 6000 m in the deeper basin of the Gulf of Suez [9]. The basal pre-rift section features sandstones of the “Nubian Sandstone” (Palaeozoic to Lower Cretaceous) that overlie the Precambrian basement. This includes the Lower Paleozoic Qebliat Group, Carboniferous Ataqa Group, and Lower Cretaceous Malha Formation. Following Cretaceous marine transgression, sandstones, limestones, and shales were deposited, forming the Raha, Abu Qada, Wata, and Matulla Formations. The Sudr Formation, with its Brown Limestone and Chalk members, is a potential regional source rock. The Esna Shales, marking the Paleocene-Eocene boundary, and the overlying Thebes Limestone, which represents the peak of the transgression, complete the sequence [51,52,53].
Geological processes in the late Oligocene are thermal doming, uplift, erosion, and minor igneous activity, preceded by Syn-rift sedimentation. Consequently, no Oligocene sediments are found in the October field, where Miocene strata rest unconformably on pre-rift sediments and basement [33,54]. Intensive subsidence and the formation of the present structural style occurred just before or during the Miocene, characterized by early extension, fault-block rotation, and marine transgression. Miocene deposits, about 2000 m thick, show rapid facies changes. The basal Nukhul Formation in fault blocks west and north of the field serves as an important reservoir. The overlying Rudeis Formation, comprising calcareous shales and argillaceous limestones, provides a seal and includes the Asl Member as a thin reservoir [55]. The Kareem Formation, with calcareous shales and fine-grained sandstones, does not hold commercial reservoirs in the October field but locally on-laps pre-Miocene strata. Middle Miocene uplift led to the deposition of extensive evaporites, forming a regional seal across the Gulf. Pliocene siliciclastics and thin evaporites, up to 1300 m thick, rest unconformably on the Zeit Formation. Regional thickening of these sediments to the northeast occurred due to Syn-depositional movements along bounding faults, with significant isostatic uplift affecting the onshore rift shoulders [56,57,58]. Abd El-Baki [20] delineated the depositional and stratigraphic evolution of the Gulf of Suez into three distinct stages: Pre-Carboniferous to Eocene, Lower Miocene, and Middle to Upper Miocene. The first stage is notable for its hydrocarbon reservoir potential, the second stage is defined by its dual role as a source and reservoir, and the third stage marks the culmination of the Gulf of Suez’s depositional history.
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Figure 2. Generalized chronostratigraphic column, lithostratigraphy and tectonic events of the Gulf of Suez Basin [59].
Figure 2. Generalized chronostratigraphic column, lithostratigraphy and tectonic events of the Gulf of Suez Basin [59].
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Mostafa [60] identified the organic-rich Upper Senonian Dawi Formation’s Brown Limestone and the Lower Eocene Thebes Formation carbonates as key source rocks for hydrocarbon generation in the Gulf of Suez. The Brown Limestone Formation is characterized by its hard, brown, phosphatic limestones, interbedded with argillaceous and cherty layers, along with streaks of marls and shales. The formation’s consistent lithology, thickness, and significant organic matter and phosphate content suggest that during their deposition surface layer of the water column was cool and oxygen rich so it is not misinterpreted as the conditions of the actual source rock beds was in oxidative environment [61]. Al-Atta [62] noted that Eocene limestones were deposited under marine conditions on top of the Cretaceous strata.
The Rudeis Formation is primarily divided into two units: Lower and Upper Rudeis. The Lower Rudeis unit consists predominantly of brownish, fine-grained marls interbedded with highly calcareous, ferruginous, and partially glauconitic sandstones, along with occasional limestone layers [49,63]. In contrast, the Upper Rudeis unit features calcareous shales interlayered with coarse, fossiliferous sandstones and some limestone and marl streaks. The transition between these units is marked by a mid-Clysmic unconformity, which is believed to be associated with a significant regional tectonic event that occurred approximately 17 My ago [60].
The Belayim Formation, which conformably overlies the Kareem Formation and underlies the South Gharib Formation, represents the oldest strata within the Ras Malaab Group. It marks the onset of the primary Miocene evaporite cycle and is characterized by thick beds of white to grey, hard crystalline anhydrite, interbedded with grey to green, soft to medium hard shales, and fine to medium-grained sandstones. The clastic and carbonate sections within this formation are considered prime targets for oil reservoirs in the Gulf of Suez, while the evaporitic sequence serves as an excellent seal and cap rock for the underlying hydrocarbon reservoirs [34,64].
Miocene rocks, which are important as source and reservoir rocks, include marine and terrestrial deposits.
During the early burial stage, kerogen forms from organic matter, such as plant and algal material, that is initially preserved in reducing environments during the sedimentation process. This process involves reduced microbial degradation of organic matter (under reducing conditions, only specialized microbes with slower metabolism can live and therefore the chance to preserve OM is higher), followed by geochemical polymerization and condensation reactions as burial depth and temperature increase, transforming organic matter into kerogen.
As burial temperatures exceed 70 °C [65], thermal degradation gradually breaks down kerogen into various hydrocarbons, beginning with the formation of predominantly liquid oil during the early catagenesis stage, followed by an increasing generation of wet gas and ultimately dry gas during the metagenesis stage.

3. Materials and Methods

Geochemical data from subsurface cutting samples of Upper Cretaceous (Upper Senonian), Eocene, and Middle Miocene strata from ten wells in the October field, central Gulf of Suez (A-1 through A-10), were provided for this study (EGPC. provided the necessary data). The data comprises Total Organic Carbon content (TOC) and Rock-Eval data (Tables S1 and S2, Table 1 and Table 2) from 135 cutting samples of Senonian Brown Limestone Formation, 105 sample of the Eocene Thebes Formation, and 8 samples of the Middle Miocene Lower Rudeis Formation (wells A-1–A-10).
In addition, Vitrinite reflectance measurements of 22 samples from well A-5 were provided (by the Egyptian General Petroleum Corporation, Maadi, Cairo) to assess the thermal maturity of source rocks (Table 3).

3.1. TOC and Rock-Eval Pyrolysis

For TOC and Rock-Eval pyrolysis analysis, a Rock-Eval 6 instrument (Vinci Technologies, Nanterre, France) was used to measure hydrocarbon yields (S1, S2) and thermal maturity parameters (Tmax, HI, OI, PI) on 135 cutting samples from the Upper Senonian Brown Limestone Formation across four wells (A-6, A-8, A-8, A-5, and A-4; Table S1). In the Eocene Thebes Formation, 105 cutting samples were obtained from six wells (A-7, A-2, A-3, A-5, A-8, and A-1; Table S2). For the Middle Miocene Lower Rudeis Formation, 8 cutting samples were gathered from two wells (A-5 and A-10; Table 1). Additionally, 29 cutting samples were collected from the Middle Miocene Belayim Formation across three wells (A-2, A-3, and A-9; Table 2).
The TOC content of the Upper Cretaceous Brown Limestone Formation ranges from 0.7–5.8 wt% (Table S1), with notably high hydrocarbon potential (S2) values between 0.79–51.63 mg HC/g rock (Table S1). The Eocene Thebes Formation exhibits a TOC range of 1–4.44 wt% (Table S2), with corresponding S2 values ranging from 0.84–26.07 mg HC/g rock (Table S2). In the Middle Miocene Lower Rudeis Formation, TOC values range from 0.56–1.1 wt% (Table 1), with S2 values averaging 0.4 wt% and 1.23 mg HC/g rock (Table 1). The Middle Miocene Belayim Formation samples have TOC values ranging from 0.51 to 1.3 wt% (Table 2), with S2 values averaging 0.62 wt% and 5.69 mg HC/g rock (Table 2).
The S1 values of the Upper Senonian Brown Limestone samples from wells A-6, A-8, A-5, and A-4 range from 0.03–4.98 mg HC/g TOC (Table S1). For the Eocene Thebes samples, high S1 values of 0.03–14.27 mg HC/g TOC (Table S2). The Lower Rudeis samples from the Middle Miocene exhibit S1 values of 0.02–0.15 mg HC/g TOC (Table 1), while the Middle Miocene Belayim samples show low S1 values of 0.07–0.96 mg HC/g TOC (Table 2). The production index (PI) values show considerable variability across the source rock formations. PI values in the Upper Cretaceous samples are generally low, ranging from 0.009–0.186 (Table S1). Similarly, the Eocene samples exhibit low PI values, ranging from 0.01–0.46 (Table S2). Lower PI values are also recorded in the Middle Miocene formations, with the Lower Rudeis Formation ranging from 0.04–0.17 (Table 1), and the Belayim Formation showing PI values between 0.04–0.26 (Table 2).
The hydrogen index (HI) is a key parameter in determining the type of organic matter within source rocks [66,67,68,69,70,71,72]. The Brown Limestone Formation exhibits high HI values ranging from 88–930 mg HC/g TOC (Table S1). Most Thebes Formation samples show relatively elevated HI values, ranging from 79–687 mg HC/g TOC (Table S2). In contrast, the Lower Rudeis Formation samples have very low HI values of 42–79 mg HC/g TOC (Table 1). The Belayim Formation samples have HI concentrations ranging from 80–529 mg HC/g TOC (Table 2).
The pyrolysis Tmax measurements show variations across the studied intervals (Tables S1 and S2, Table 1 and Table 2). In the Upper Senonian Brown Limestone samples, Tmax values range between 426–443 °C. The Eocene Thebes and Middle Miocene Lower Rudeis and Belayim samples exhibit slightly higher Tmax values, ranging from 421 to 446 °C, which represents a critically important variation that reflects key geological controls on the system’s behaviour.

3.2. Calibration Data

Vitrinite reflectance measurements of 22 samples were provided (by the Egyptian General Petroleum Corporation) to assess the thermal maturity of source rocks and their potential for hydrocarbon generation (Tables S1 and S2, Table 1 and Table 2). Visual kerogen analysis involved examining kerogen concentrates under a transmitted light microscope to identify and classify the types of organic matter present in sedimentary rocks. The process involved isolating kerogen from rock samples through acid treatments that removed carbonate and silicate minerals. The kerogen was then analyzed based on its optical properties, including color, fluorescence, and morphology, which provide insights into its type (e.g., algal, woody, amorphous) and thermal maturity. This qualitative analysis is critical for assessing hydrocarbon generation potential, as it complements quantitative methods like pyrolysis and vitrinite reflectance (typically expressed as %Ro; Table 3). Some %Ro measurements were excluded from the calibration due to inconsistencies or insufficient data quality. These exclusions were based on factors such as ambiguous maceral identification (e.g., mixed vitrinite and inertinite signals), potential contamination, or measurements on samples with low organic carbon content, which can lead to unreliable results. The remaining dataset was carefully selected to represent the most reliable and consistent measurements, ensuring robust calibration of maturity models.
The temperature data were provided from seven measurements in a single well (A-5), providing crucial insights into the subsurface thermal regime (Table 4). Bottom Hole Temperature (BHT) measurements are typically recorded during or immediately after drilling, but these raw readings often underestimate the true formation temperature due to the cooling effect of drilling mud. The BHT data were corrected using industry-standard empirical correction methods to improve accuracy [73].
The quality of these measurements is generally considered moderate, as the single well may limit representativeness and introduce spatial uncertainty. However, when calibrated against regional geothermal gradients or other wells, the data can provide a reliable basis for estimating thermal maturity. Despite potential inaccuracies, the corrected BHT values contribute valuable input for maturity modelling, complementing other thermal indicators such as vitrinite reflectance and pyrolysis Tmax.

3.3. Well Log Response

Well-log responses are a valuable tool for evaluating source rocks, providing indirect measurements of their organic richness, lithology, and thermal maturity (Figure 3). The method involves analyzing a suite of well logs, such as gamma-ray (GR), resistivity, density, sonic, and neutron logs, to identify source rock intervals and estimate their hydrocarbon generation potential. The gamma-ray log measures natural radioactivity, primarily associated with uranium, thorium, and potassium in rocks. Organic-rich source rocks often exhibit elevated gamma-ray values due to uranium enrichment, which is commonly associated with organic matter [65,74].
Source rocks containing hydrocarbons or high organic content generally show increased resistivity compared to surrounding formations due to the insulating nature of organic matter and hydrocarbons. This response is beneficial in identifying mature, hydrocarbon-generating source rocks. Sonic logs measure the travel time of acoustic waves through the formation. Organic-rich rocks often show increased transit times due to the low acoustic velocity of kerogen. This can also indicate porosity and the presence of hydrocarbons. Some well logs, like resistivity and sonic, can indirectly reflect thermal maturity by identifying changes in organic matter properties due to increased heat exposure, such as higher resistivity in mature source rocks [65,75].
This method allows for the identification, quantification, and evaluation of source rock properties, even in areas where core or cutting samples are unavailable, providing a cost-effective means of assessing hydrocarbon potential.

3.4. Basin Modeling–Approach and Data

Basin modelling was conducted on well A-5 (This well, situated in the central part of the study area, reaches a total depth of 14,050 ft. Vitrinite reflectance and temperature measurements were conducted on this well to assess thermal maturity) in the October field, Central Gulf of Suez, with the primary objective of identifying specific periods of burial and uplift that shaped the basin’s configuration. PetroMod 2019 @Schlumberger, was utilized to reconstruct/the burial and thermal histories of the basin. The maturity of the Upper Cretaceous, Eocene, and Middle Miocene source rocks were calculated using the “EASY%Ro” model. The modelling results were validated with measured vitrinite reflectance (%Ro) and temperature well data (Table 3 and Table 4, respectively). The input data included lithologies, thickness, and age of the rock units, along with initial estimates for timing and amount of erosion as detailed in Table S3 and validated/adjusted during model calibration. The timing of hydrocarbon generation for the different source rocks was modelled using the kinetic data of TII-S(A) for kerogen type II [74].

4. Results

4.1. Well Log Responses

According to Passey et al. [75], the separation between sonic and resistivity logs indicates the presence of source rock, which is influenced by the degree of thermal maturity and signifies a mature source rock. In the October field, the Middle Miocene Belayim Formation was encountered in three wells (A-2, A-3, and A-9), the Middle Miocene Lower Rudeis Formation was identified in two wells (A-5 and A-10), the Eocene Thebes Formation was drilled in seven wells (A-1, A-2, A-3, A-5, A-7, and A-8), and the Upper Senonian Brown Limestone Formation was intersected in four wells (A-3, A-5, A-6, and A-8).
Figure 3 illustrates the organic-rich intervals within the potential source formations in several wells studied. In the Belayim Formation, the sonic log (trace DT) reveals a high interval transit time ranging from 87 to 170 µs/ft, coupled with low resistivity log (trace LLD) readings between 0.28 and 1.37 Ohm.m, indicating limestone facies. In the Lower Rudeis Formation, the sonic log (trace DT) shows high interval transit times of 65 to 105 µs/ft, while the medium resistivity log (trace LLD) readings range from 2.02 to 114 Ohm.m, suggesting limestone and shale facies. For the Thebes Formation, the sonic log (trace DT) exhibits high interval transit times of 48 to 103 µs/ft, alongside high resistivity log (trace LLD) readings from 1.48 to 1204 Ohm.m, indicative of limestone lithofacies. Lastly, in the Brown Limestone Formation, the sonic log (trace DT) shows interval transit times of 52 to 75 µs/ft, and the resistivity log (trace LLD) readings range from 3.05 to 1749 Ohm.m, reflecting limestone and shale facies.

4.2. Basin Modeling

Analyzing the thermal evolution of sedimentary basins is crucial for assessing the thermal maturity of potential source rocks, which directly impacts the timing and depth of hydrocarbon generation [76,77,78]. 1D basin models were developed for the well A-5 (Figure 4) to reconstruct the burial and temperature history of the October field. For the calibration of the modelling results, vitrinite reflectance data and temperature measurements are essential because several processes and parameters, like basal heat flow or timing and amount of erosion, are not well determined by the available data, although they significantly impacting modelling results [6,22]. An agreement between measured and simulated maturity can be achieved by geologically justified adjustments of the basal heat flow and timing of periods of uplift and erosion as the most critical factors. In addition, the best possible definition of lithological properties of the modelled rock sequence and the determination of surface temperature change throughout the geological evolution of the basin are essential for a successful reconstruction of the burial and temperature history of a study area by basin modelling. The validity of the October field’s reconstructed burial and thermal histories is demonstrated by a good concurrence of modelling results and measured calibration data such as vitrinite reflectance and temperature data.

4.2.1. Thermal Boundary Conditions

To determine the temperature evolution of a sedimentary basin, it is essential to define the thermal boundary conditions at the base (basal heat flow, HF) and at the top (sediment-water interface temperatures SWIT) of a model, both assigned across the geologic time scale [79,80]. Fast alterations of the thermal regime in the sedimentary column of a basin result in a non-steady (transient) state, which becomes significant during periods of fast deposition or erosion, or when rifting events rapidly change crustal heat conditions [22,80].
For the definition of the upper-temperature boundary (SWIT) the integrated PetroMod-tool based on the compilation by Wygrala [81] was used. Figure 5 shows the evolution of surface temperature through the geological history of the study area. The evolution of the basal heat flow through time (Figure 5) was modeled using an integrated algorithm based on Jarvis and McKenzie [82] to simulate rift-related heat flow effectively.
The 9 Ma boundary was selected because post-rift thermal stabilization in the Gulf of Suez renders younger adjustments negligible for hydrocarbon maturation, while present-day water-column effects were accounted for as fixed boundary conditions with minimal impact on deeper thermal regimes. The 25–15 Ma HF fluctuations are robustly constrained by syn-rift tectonic models, local vitrinite reflectance/apatite fission-track data, and comparable studies in analogous rift basins.

4.2.2. Burial and Thermal History

The burial history diagram (Figure 6) provides a numerical reconstruction of the sedimentary section over time and space and its respective temperature evolution, illustrating the time-depth relationship for the sediments outlined in Table 4.
Early Miocene’s major uplift and erosion event terminated the pre-rift phase. Renewed subsidence continued throughout the Miocene interrupted by the Post-Nukhul inversion and the Late Miocene (Mid-Clysmic) tectonic reactivation. Intensive subsidence resumed in the Pliocene, marked by the deposition of Post-Zeit sediments [16,22,83,84].
In the Pre-rift, uplift occurred from ~100–25 Ma (Late Cretaceous to Oligocene), marked by the deposition of formations such as Raha, Wata, Matulla, Dawi, Sudr, Esna, Thebes, formations. Middle Eocene Limestone, and Abu Zeneima. In contrast, the Syn-rift sedimentation was characterized by more rapid and progressive rates compared to the Pre-rift phase. During the main rifting phase (~25–21 Ma, Oligocene-Miocene), rapid subsidence led to the deposition of significant thicknesses. This was followed by renewed tectonic activity in the post-Nukhul event (~21–19 Ma, latest Aquitanian-earliest Burdigalian). Subsequently, a slower subsidence rate (~17–14.5 Ma) is marked by the Upper Rudeis Formation and Kareem Formation deposition. In the early post-rift phase (~14.5–6 Ma, Middle-Late Miocene), thermal subsidence was characterized by a slow to moderate rate due to the relative tectonic stability across the Red Sea rift system. This period saw the deposition of the Belayim, South Gharib, and Zeit formations [37]. The Pliocene to present period experienced rapid Post-Zeit deposition characterized by high sedimentation and subsidence rates, driven by active tectonics and substantial sediment influx.
During the Oligo–Miocene rifting phase, the maximum heat flow reached 100 mW/m2, while the Miocene and Mio-Pliocene rifting phases recorded peak values of 120 mW/m2 and 80 mW/m2, respectively. The relatively low thermal conductivity of basin-fill sediments, such as the Rudeis, Belayim, and Kareem formations, led to an elevated geothermal gradient, causing the underlying sediments to warm—a phenomenon known as the “Blanketing Effect” [85,86]. Conversely, the high thermal conductivity of the South Gharib Formation’s salt and the Anhydrite in the Zeit Formation resulted in increased temperatures at the top of the salt (Zeit Formation) and lower temperatures in the underlying Belayim and Kareem formations.
The heat flow estimates for the modelled well (A-5) were carefully calibrate using the thermal maturity parameter vitrinite reflectance (%Ro) and temperature well data (Table 3 and Table 4). Vitrinite reflectance increases with temperature and indicates the highest temperature organic matter has experienced during burial [80]. The EASY%Ro algorithm [87] was used to calculate vitrinite reflectance values and calibrate the model to measure data (Figure 4). Vitrinite reflectance (%Ro) measurements in Well A-5 (Table 3) exhibit non-monotonic trends with depth, likely due to post-burial uplift and heterogeneous thermal regimes. While deeper samples (e.g., 16,100 ft, %Ro = 1.75) record higher paleo-maturity, some intermediate-depth samples show lower Ro, possibly reflecting reworked vitrinite or suppressed Ro in Sulfur-rich marine kerogen. These variations were incorporated into the basin model by calibrating heat flow against both Ro and pyrolysis Tmax (Tables S1 and S2, Table 1 and Table 2), ensuring reliable maturity predictions.
The observed inconsistencies in vitrinite reflectance (%Ro) values with depth in Well A-5 can be attributed to the complex geological history of the Gulf of Suez. Multiple phases of rifting, subsidence, and uplift have caused some deeper sections to experience higher paleo-temperatures before being uplifted, resulting in elevated Ro values at shallower depths. Additionally, localized variations in heat flow, such as from magmatic intrusions or fluid migration, along with potential issues like reworked vitrinite particles or Sulfur-rich kerogen suppressing Ro measurements, contribute to the non-linear Ro trends.
Discrepancies between Ro and pyrolysis Tmax values arise because Tmax reflects current thermal conditions, while Ro records peak paleo-temperatures, particularly in uplifted sections. Kerogen type also plays a role, as Type I/II kerogen (common in the studied formations) typically shows lower Tmax values compared to Type III kerogen at similar maturity levels. Despite these variations, the 1D basin model was carefully calibrated using multiple maturity indicators (Ro, Tmax, and BHT data), ensuring reliable predictions of hydrocarbon generation windows. Sensitivity testing further confirmed the model’s robustness in accounting for these complexities.

4.2.3. Hydrocarbon Generation

After developing burial and thermal history models and identifying the oil window for the Upper Senonian Brown Limestone Formation, Eocene Thebes Formation, and Middle Miocene Lower Rudeis and Belayim formations, we observed considerable variability in the oil window. The hydrocarbon zone in the A-5 well (Figure 7) is summarized as follows:
  • The Middle Miocene Belayim source rock has not yet entered the early oil window (0.55–0.70 %Ro) and is classified as immature (0.00–0.55 %Ro).
  • The Middle Miocene Lower Rudeis source rock reached the early oil window (0.55–0.70 %Ro) at 12.64 Ma at 6514 feet, entered the main oil window (0.70–1.00 %Ro) at 5.69 Ma at 9458 feet, and continues to remain in this window.
  • The Eocene Thebes source rock entered the early oil window (0.55–0.70 %Ro) at 21 Ma at 3763 feet, shifted to the main oil window (0.7–1.0 %Ro) at 10.80 Ma at 8690 feet, and has been in the late oil window (1.00–1.30 %Ro) since 1.60 Ma at 13,236 feet.
  • The Upper Cretaceous (Upper Senonian) Brown Limestone source rock entered the early oil window (0.55–0.7 %Ro) at 39 Ma at a depth of 5416 feet, transitioned to the main oil window (0.7–1.0 %Ro) at 13 Ma at 8594 feet, and remains in this window to the present.
The Pepper and Corvi [74] Type II-S kinetic model was selected because it is specifically designed for sulfur-rich marine source rocks like those in our study area (evidenced by our geochemical data showing high sulfur content in the Brown Limestone and Thebes formations). This model better predicts hydrocarbon generation timing compared to generic Type II models, matching our observed maturity indicators (%Ro, BHT). The choice aligns with regional studies of similar Tethyan marine basins. The maximum predicted transformation ratio in the A-5 well ranges from 23% at the onset of expulsion to 50% at the present day. The modelling results indicate a significant increase in the transformation ratio from the Late Pliocene to Recent (Figure 8). In the central Gulf of Suez, particularly within the October field, crude oils show a strong correlation with the Brown Limestone Formation, with oil densities between 17° and 30° API [60]. Heavy oils, with densities ranging from 10° to 20° API, are generally expelled at transformation ratios below 50%, characterized by a low gas-oil ratio (GOR) and an asphaltene content of 20–25% [88]. Accordingly, our findings suggest the presence of heavy oils (10–20° API) with an asphaltene content of 20–25%.
The transformation ratio plot for the Brown Limestone Formation (Figure 8) indicates that transformation began in the Upper Cretaceous (53 Ma) and reached approximately 30% by the Miocene (14.3 Ma). In the Thebes Formation, the transformation started in the Late Eocene (45 Ma) and reached about 6.4% by the Miocene (16.4 Ma). The Lower Rudeis Formation initiated transformation in the Middle Miocene (18.7 Ma), reaching around 3.6% by the Miocene (9.2 Ma). Finally, the Belayim Formation began its transformation in the Middle Miocene (11.2 Ma), achieving approximately 0.63% by the Miocene (6.8 Ma).

4.2.4. Petroleum System Event Chart

The petroleum system event chart (Figure 9) outlines the sequence of elements and processes within the petroleum system in the October field, highlighting the relative timing and associated risks. The findings align with previous studies [41], which indicated that primary and secondary migration occurred from the Late Pliocene to Quaternary. The Gulf of Suez oil fields typically feature distinct provinces of structural traps [89,90], meaning that hydrocarbon migration and accumulation are primarily influenced by structural evolution [91,92]. In the A-5 well, hydrocarbon expulsion began in the Late Pliocene (2.52 Ma).
Figure 9 presents a summarised event chart of the petroleum system in the October field, focusing on the A-5 well. This chart illustrates the chronological relationships between the key petroleum elements and processes. It highlights four source rocks: the Upper Cretaceous Brown Limestone, Eocene Thebes, and Middle Miocene Lower Rudeis and Belayim formations. These source rocks exhibit fair to excellent organic richness, containing types I, II, and II/III kerogen, and are in various stages of maturity, from immature to mature. The Lower Senonian Matulla Formation and the Asl Member of the Upper Rudeis Formation serve as reservoir rocks, while the evaporites of the Belayim Formation function as an effective seal. The overburden rocks in the October basin, which include the Zeit, S. Gharib, Belayim, Kareem, and Nukhul formations, have a total thickness ranging from 4844 to 8916 ft. The lithology of these overburden rocks consists of limestone, shale, anhydrite, and evaporite [16].

5. Discussion

The Upper Cretaceous to Middle Miocene succession in the October field, Central Gulf of Suez, was examined to identify the characteristics of its organic matter. This analysis utilised multiple geochemical proxies, drawing on previously presented data from ten well sites (A-1 to A-10) as tabulated in Tables S1 and S2, Table 1 and Table 2.

5.1. Source Rock Characteristics and Hydrocarbon Potential

Basins with successful petroleum discoveries typically contain proven organically rich source rocks that have undergone deep burial in basinal locations. Identifying the source rock system typically begins with assessing the abundance of organic matter and generating potential [93]. Key factors such as kerogen typing and thermal maturity levels must also be evaluated [6]. For organic richness, a minimum of 0.5 wt% TOC is considered necessary [94,95]. The Upper Cretaceous (Brown Limestone) samples, comprising 135 samples from four wells, exhibit TOC content as high as 5.8% in the A-6 well (Table S1). This indicates a fair to excellent level of organic richness (mature oil zone) and demonstrates excellent hydrocarbon-generating potential (Figure 10).
The overlying Eocene (Thebes Formation) samples exhibit favourable source rock characteristics. Among the 105 samples from six wells, most display good to excellent source rock quality, with TOC values ranging from 1% to 4.4% (Table S2). The TOC and S2 values suggest that the Eocene Thebes Formation in the October field can be classified as an effective source rock within the high thermal maturity range.
The Middle Miocene (Lower Rudeis Formation) samples, comprising eight samples from two wells, exhibit low organic content. Most of these samples exhibit fair to good source rock quality, with TOC values ranging from 0.7% to 1% (Table 1). These TOC and S2 values indicate that the Lower Rudeis Formation in the October field can be classified as a poor source rock due to its low thermal maturity, due to insufficient burial.
The Middle Miocene (Belayim Formation) samples exhibit modest organic content. Among the 29 samples collected from three wells, most exhibit fair to good source rock quality, with a few samples indicating high organic content, as indicated by TOC values ranging from 0.42% to 1.3% (Table 2). These TOC and S2 values suggest that the Belayim Formation in the October field may serve as a potential source rock, albeit still immature due to insufficient burial. High maturity indicators in source rocks with low organic content and limited hydrocarbon potential have been widely documented (e.g., [97,98,99]. These studies suggest that a source rock with low organic content (TOC < 0.5 wt%) may still have some hydrocarbon potential in the early stages of maturity, even though it is generally considered a poor source rock.
The increased organic matter content observed in the eastern study area (wells A-4, A-5, A-6, and A-8) suggests a greater influx of organic material (this influx might be driven by factors such as river discharge, upwelling, or depositional settings that favor organic material deposition) compared to the western wells (particularly A-3 and A-9), where TOC values below 0.5% imply that the Middle Miocene Lower Rudeis Formation is not a significant source rock. The low S2 values (0.31–1.23 mg HC/g rock; Table 1) further indicate poor source rock potential (Figure 10). Similarly, the low TOC (0.4–1.3%, Table 2) and S2 (0.62–6 mg HC/g rock) values in the Belayim Formation samples indicate limitations in the Middle Miocene source rock potential within the study area (Figure 10). In addition, the low S1 values suggest that the hydrocarbons produced are of indigenous origin (Figure 11).

5.2. Organic Matter Type

The kerogen types in the studied Upper Cretaceous to Middle Miocene strata were primarily classified based on Hydrogen Index (HI) values. According to established classifications [95,100,101,102,103], kerogen types can be categorized as type I (HI > 600 mg HC/g TOC), type II (HI 300–600 mg HC/g TOC), type II–III (HI 200−300 mg HC/g TOC), type III (HI 50−200 mg HC/g TOC), and type IV (HI < 50 mg HC/g TOC). To further assess the kerogen types within the studied succession, HI, OI, and TOC values were plotted against S2 values (Figure 10). This approach enhances the accuracy in predicting the potential generation of hydrocarbon products, such as oil and gas [104,105].
In the Upper Cretaceous Brown Limestone Formation, HI values range from 88–930 mg HC/g TOC and OI values from 18–89 mgCO2/g TOC (Table S1, Figure 12), suggesting the presence of type I and II kerogen. This relationship is effectively illustrated using a modified Van Krevelen diagram [106]. Similarly, the Eocene Thebes Formation exhibits HI values between 79–687 mg HC/g TOC and OI values from 20–262 mg CO2/g TOC, indicating a mixture of type I and II kerogen (Table S2, Figure 12). The Middle Miocene Lower Rudeis Formation shows HI values from 42–170 mg HC/g TOC and OI values between 32 and 268 mg CO2/g TOC, characteristic of type III kerogen (Table 1, Figure 12). In contrast, the Middle Miocene Belayim Formation displays HI values ranging from 80–529 mg HC/g TOC and OI values from 85–496 mg CO2/g TOC, indicating the presence of type II and II/III kerogen (Table 2, Figure 12).

5.3. Thermal Maturity and Hydrocarbon Generation Potential

Assessing the thermal maturity level in source rocks requires the visual identification of kerogen assemblages, as noted by [108]. Various optical and geochemical parameters, particularly Production Index (PI) and Tmax, were utilized to determine the thermal maturity within the Upper Cretaceous to Middle Miocene sequence (Figure 7). Additionally, a plot of HI versus TOC, as described by Jackson et al. [105], was employed to characterize the source rocks under investigation (Figure 7).
Thermal maturity levels in source rocks are often assessed through Tmax values, which indicate the extent of organic matter conversion. The Brown Limestone Formation (Upper Cretaceous) exhibits Tmax values between 426–443 °C, placing it at the threshold of the mature zone. In contrast, the Thebes Formation (Eocene) shows Tmax values ranging from 421–444 °C, suggesting it is within the immature zone, yet on the verge of entering maturity. Selected samples from the Lower Rudeis Formation (Middle Miocene) are predominantly in the immature zone, with Tmax values of 422–444 °C, indicating low conversion levels. The Belayim Formation (Middle Miocene) spans from immature to mature (oil zone), with Tmax values ranging from 422–446 °C. These findings are essential for understanding these formations’ thermal evolution and hydrocarbon potential in the October field.
The TOC and HI values (Figure 7) indicate varying hydrocarbon potential across the studied formations. The Upper Cretaceous Brown Limestone Formation is identified as a fair to good source for oil. The Eocene Thebes Formation is also considered a fair to good oil source, with some samples showing potential for oil and gas generation. The Middle Miocene Lower Rudeis Formation is considered a potential oil source, with specific samples indicating the potential for both oil and gas. Lastly, the Middle Miocene Belayim Formation is characterized as a fair to good oil source rock.
Hydrocarbon generation throughout the Gulf of Suez Basin is primarily influenced by its complex tectonic evolution, structural setting, and diverse sedimentary history. The basin hosts prolific source rocks, including the Upper Cretaceous Brown Limestone and the Eocene Thebes Formation, which are thermally mature due to the high heat flow associated with rifting. Variations in geothermal gradients, burial depths, and the presence of salt structures significantly impact the timing and efficiency of hydrocarbon generation. Additionally, the interplay of tectonic uplift, erosion, and subsequent sediment infill has created multiple kitchens for hydrocarbon generation across different stratigraphic levels. The basin’s extensional tectonics have also resulted in fault-bound traps and tilted blocks, crucial in hydrocarbon migration and accumulation. Understanding these factors is essential for evaluating the basin’s exploration potential and unlocking new plays.
Seismic data from the Gulf of Suez Basin reveal potential hydrocarbon kitchen areas in its deeper parts, indicating that source rocks, particularly the pre-rift such as the Cretaceous (Malha Formation, Raha Formation, and Themed Formation) and older Paleozoic rocks, and early syn-rift sequences deposited during the initial rifting phase (Late Oligocene to Early Miocene), including the Nukhul Formation and parts of the Rudeis Formation, which are rich in organic-rich shales, are buried to greater depths in certain sub-basins, enhancing their thermal maturity and hydrocarbon generation potential.
The timing of hydrocarbon generation in the Gulf of Suez Basin is closely tied to its tectono-thermal history, particularly the heat flow peaks associated with rifting events during the Oligocene and Miocene. These heat flow peaks accelerated the thermal maturation of organic-rich source rocks, driving the generation and expulsion of hydrocarbons. Without these thermal events, the petroleum system might still function, but at a slower rate, with delayed hydrocarbon generation and potentially less mature oil or gas accumulations. The heat flow peaks also impacted the distribution and quality of the generated hydrocarbons, enhancing the system’s efficiency by providing sufficient heat to transform kerogen into oil and gas. Therefore, while the petroleum system could operate without these peaks, the overall timing, volume, and quality of hydrocarbon generation would likely be significantly reduced.
The Late Pliocene inversion in the Gulf of Suez Basin played a dual role in the petroleum system, both enhancing and challenging its potential. This tectonic event, driven by regional compressional stresses, led to the reactivation of pre-existing faults and the formation of new structural traps, significantly improving hydrocarbon entrapment opportunities in some areas. However, in other cases, the inversion caused deformation or breaching of existing reservoirs, potentially leading to hydrocarbon leakage or loss. Additionally, the inversion uplifted certain areas, which may have altered burial depths and thermal histories, influencing the maturation and preservation of source rocks and hydrocarbon accumulations. Overall, while the Late Pliocene inversion introduced risks to some reservoir structures, it was also critical in creating new structural traps and enhancing the complexity of the basin’s petroleum system.

6. Conclusions

The hydrocarbon potential of the Gulf of Suez Basin is characterised by a temporal progression of source rocks from youngest to oldest times. In the Middle Miocene, the Belayim Formation (14–11 Ma) exhibits fair to good source rock quality (TOC 0.42–1.3%) with mixed Type II and II/III kerogens, though it remains immature (%Ro 0.55–0.7) with only 0.63% transformation by 6.8 Ma, while its evaporites serve as an effective regional seal. The slightly older Lower Rudeis Formation (16–14 Ma) exhibits poor source potential, characterised by low organic content and Type III kerogen. It entered the oil window at 13 Ma and reached a 3.59% transformation by 9 Ma. Moving deeper, the Eocene Thebes Formation demonstrates excellent source quality with Type I/II kerogens, entering the oil window at 21 Ma, beginning transformation at 45 Ma, and achieving 6.42% transformation by 16 Ma. The intervening Paleocene (66–56 Ma) represents a depositional gap with no significant source rocks due to shallow marine conditions and potential erosion. The most prolific source rock is the Upper Cretaceous Brown Limestone, exhibiting fair to excellent TOC values with Type I/II kerogens, which entered the oil window at 39 Ma, commenced transformation at 53 Ma, and reached ~30% transformation by 14 Ma. This stratigraphic sequence works in conjunction with reservoir units like the Matulla Formation and Asl Member, while being capped by the Belayim evaporites and overlain by a substantial overburden (4844–8916 ft) of Zeit, South Gharib, Kareem, and Nukhul formations composed of limestone, shale, anhydrite, and evaporite, which collectively control the thermal maturation and hydrocarbon potential across the basin’s geological history.

Supplementary Materials

The following supporting information can be downloaded at: https://www.mdpi.com/article/10.3390/resources14070114/s1, Table S1. Datasets of the TOC and Rock-Eval pyrolysis results of the studied samples from the Upper Cretaceous Brown Limestone Formation, October field, Central Gulf of Suez. Table S2. Datasets of the TOC and Rock-Eval pyrolysis results of the studied samples from the Eocene Thebes Formation, October field, Central Gulf of Suez. Table S3. Input data needed for construction of 1D basin modeling of one representative well: A-5. Sh: shale, S.st: sandstone, L.st: Limestone, Anh: Anhydrite.

Author Contributions

Conceptualization, M.B. and M.R.; methodology, M.B. and M.R.; software, M.R.; validation, M.B., D.E.G. and R.O.; formal analysis, M.B. and M.R.; investigation, M.R.; resources, M.B., D.E.G. and D.E.A.; data curation, M.B. and M.R.; writing—original draft preparation, M.R.; writing—review and editing, M.B., M.R., D.E.G., R.O. and D.E.A.; visualization, M.R.; supervision, M.B.; project administration, M.B.; funding acquisition, M.R. All authors have read and agreed to the published version of the manuscript.

Funding

This research received no external funding.

Data Availability Statement

The datasets generated during and/or analyzed during the current study are not publicly available due to authority restrictions.

Acknowledgments

The authors express their gratitude to the Egyptian General Petroleum Corporation for providing the raw materials, geochemical reports, and digital logs, and for granting permission for publication. Additionally, the authors appreciate the technical staff for their valuable contributions during the professional discussions.

Conflicts of Interest

The authors have no conflicts of interest to declare that are relevant to the content of this article. Also, the authors declare that the research was conducted in the absence of any commercial or financial relationships that could be construed as a potential conflict of interest.

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Figure 3. Computer processed interpretation (CPI) in the studied wells through organic-rich intervals in October field, (value in ft., MD). Track 4 shows the separation between sonic and resistivity log which indicates a mature source rock.
Figure 3. Computer processed interpretation (CPI) in the studied wells through organic-rich intervals in October field, (value in ft., MD). Track 4 shows the separation between sonic and resistivity log which indicates a mature source rock.
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Figure 4. Depth-plot explained the thermal maturity, (a) modelled (red solid line) and measured (+) vitrinite reflectance (%Ro). (b) the corrected static bottom-hole temperature BHT (+) plotted against depth.
Figure 4. Depth-plot explained the thermal maturity, (a) modelled (red solid line) and measured (+) vitrinite reflectance (%Ro). (b) the corrected static bottom-hole temperature BHT (+) plotted against depth.
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Figure 5. The boundary condition assessment for the October field (A-5 well, see Figure 3 for well location) including: (Top) the paleowater depth (PWD, in feet) and (Middle) the sediment-water interface temperature (SWIT, in °C), and (Bottom) the paleo-heat flow (HF, in mW/m2).
Figure 5. The boundary condition assessment for the October field (A-5 well, see Figure 3 for well location) including: (Top) the paleowater depth (PWD, in feet) and (Middle) the sediment-water interface temperature (SWIT, in °C), and (Bottom) the paleo-heat flow (HF, in mW/m2).
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Figure 6. Simulated burial and thermal history of the October field in the A-5 well.
Figure 6. Simulated burial and thermal history of the October field in the A-5 well.
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Figure 7. Simulated burial history and hydrocarbon zones in the A-5 well show the hydrocarbon generation potentialities of the source rocks in the October field.
Figure 7. Simulated burial history and hydrocarbon zones in the A-5 well show the hydrocarbon generation potentialities of the source rocks in the October field.
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Figure 8. Time-plot of the simulated transformation ratios of the organic-rich sources, Brown Limestone, Thebes, Lower Rudeis, and Belayim, through the Upper Cretaceous to Pliocene in October field.
Figure 8. Time-plot of the simulated transformation ratios of the organic-rich sources, Brown Limestone, Thebes, Lower Rudeis, and Belayim, through the Upper Cretaceous to Pliocene in October field.
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Figure 9. Petroleum event chart for the A-5 well (not to scale). The source rock is shown in dark green, the reservoir roc39k in red, the seal rock in purple, and the overburden rock in brown.
Figure 9. Petroleum event chart for the A-5 well (not to scale). The source rock is shown in dark green, the reservoir roc39k in red, the seal rock in purple, and the overburden rock in brown.
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Figure 10. The relations between the TOC and depth (ft) after Peters and Cassa [94]; and the relation between the TOC and S2 according to Dembicki [96] in the October field.
Figure 10. The relations between the TOC and depth (ft) after Peters and Cassa [94]; and the relation between the TOC and S2 according to Dembicki [96] in the October field.
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Figure 11. The relation between the TOC and S1 according to Hunt [100].
Figure 11. The relation between the TOC and S1 according to Hunt [100].
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Figure 12. Adapted Van Krevelen diagram based on Espitalie et al. [106], illustrating kerogen Type in the October wells, and the relation between the TOC and S2 according to Dembicki [107].
Figure 12. Adapted Van Krevelen diagram based on Espitalie et al. [106], illustrating kerogen Type in the October wells, and the relation between the TOC and S2 according to Dembicki [107].
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Table 1. Datasets of the TOC and Rock-Eval pyrolysis results of the studied samples from the Middle Miocene Lower Rudeis Formation, October field, Central Gulf of Suez.
Table 1. Datasets of the TOC and Rock-Eval pyrolysis results of the studied samples from the Middle Miocene Lower Rudeis Formation, October field, Central Gulf of Suez.
Well NameDepth (ft)TOC (wt%)S1 (mg HC/g Rock)S2 (mg HC/g Rock)Tmax (°C)HI (mg HC/g TOC)OI (mg CO2/g TOC)PI (S1/(S1 + S2))
A-592000.560.120.714221272680.14
97000.960.070.442842910.15
10,4500.720.10.5432691400.17
10,6500.720.114321391930.09
14,0501.10.040.8744479320.04
14,6500.540.020.3143357570.06
A-1012,1500.70.151.23433170-0.11
12,6500.70.040.4543670-0.08
Table 2. Datasets of the TOC and Rock-Eval pyrolysis results of the studied samples from the Middle Miocene Belayim Formation, October field, Central Gulf of Suez.
Table 2. Datasets of the TOC and Rock-Eval pyrolysis results of the studied samples from the Middle Miocene Belayim Formation, October field, Central Gulf of Suez.
Well NameDepth (ft)TOC (wt%)S1 (mg HC/g Rock)S2 (mg HC/g Rock)Tmax (°C)HI (mg HC/g TOC)OI (mg CO2/g TOC)PI (S1/(S1 + S2))
A-350100.680.070.824241214530.08
51700.450.070.624251384960.1
A-965501.210.284.12428340950.06
66001.010.324.174384131100.07
66501.080.223.65432338910.06
67001.280.335.59426437850.06
67501.280.266422469970.04
68001.150.355.694254951590.06
68501.120.515.244274681550.09
69001.10.314.414244011390.07
69500.550.292.84425092470.09
70001.180.212.23431189910.09
70500.920.214.554354951150.04
71000.490.292.214384511710.12
71500.70.433.074354391370.12
72000.510.962.74465291880.26
A-293801.30.141.4429801240.12
94000.660.110.874291322470.11
94300.680.11.034301512070.09
94600.710.080.824331152300.09
94900.70.070.744321062710.09
95200.90.11.34321441970.07
95500.930.131.884302022170.06
95800.80.111.524341902010.07
96100.510.070.674301311610.09
96400.70.131.54292141890.08
96700.550.161.484302692530.1
97000.60.141.054281751820.12
Table 3. Vitrinite Reflectance (Ro%) measurements which were used to evaluate the thermal maturity phase of the October field, Central Gulf of Suez, and to calibrate the constructed maturity models.
Table 3. Vitrinite Reflectance (Ro%) measurements which were used to evaluate the thermal maturity phase of the October field, Central Gulf of Suez, and to calibrate the constructed maturity models.
Well NameDepth (ft)Vitrinite (%Ro)
A-592001.03
97001.08
10,4500.95
10,6500.46
11,2501.06
11,9000.93
12,7000.57
12,9000.59
13,5500.66
13,6500.61
14,0500.96
14,6501.62
16,1001.75
16,6001.35
Table 4. Temperature measurements which were used to evaluate the thermal maturity phase of the October field in the Central Gulf of Suez and calibrate the constructed maturity models.
Table 4. Temperature measurements which were used to evaluate the thermal maturity phase of the October field in the Central Gulf of Suez and calibrate the constructed maturity models.
Well NameDepth (ft)BHT (°F)
A-55222140
11,085200
13,566256
15,575270
16,392321
16,517328
16,740330
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Barakat, M.; Reda, M.; Gamvroula, D.E.; Ondrak, R.; Alexakis, D.E. Investigating Attributes of Oil Source Rocks by Combining Geochemical Approaches and Basin Modelling (Central Gulf of Suez, Egypt). Resources 2025, 14, 114. https://doi.org/10.3390/resources14070114

AMA Style

Barakat M, Reda M, Gamvroula DE, Ondrak R, Alexakis DE. Investigating Attributes of Oil Source Rocks by Combining Geochemical Approaches and Basin Modelling (Central Gulf of Suez, Egypt). Resources. 2025; 14(7):114. https://doi.org/10.3390/resources14070114

Chicago/Turabian Style

Barakat, Moataz, Mohamed Reda, Dimitra E. Gamvroula, Robert Ondrak, and Dimitrios E. Alexakis. 2025. "Investigating Attributes of Oil Source Rocks by Combining Geochemical Approaches and Basin Modelling (Central Gulf of Suez, Egypt)" Resources 14, no. 7: 114. https://doi.org/10.3390/resources14070114

APA Style

Barakat, M., Reda, M., Gamvroula, D. E., Ondrak, R., & Alexakis, D. E. (2025). Investigating Attributes of Oil Source Rocks by Combining Geochemical Approaches and Basin Modelling (Central Gulf of Suez, Egypt). Resources, 14(7), 114. https://doi.org/10.3390/resources14070114

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