Petroleum Systems in the Geisum Area, South Gulf of Suez, Egypt: Insights from 1D Basin Modeling and Fluid Geochemistry

This study aims to define the hydrocarbon generation potential of source rocks by assessing various factors including quantity of organic matter, types of kerogen, thermal maturity, and source of organic matter input. Depositional conditions of source rocks from Thebes, Brown Limestone, and Matulla formations in Well G-9, Well GA-2 and Well GW-6, are assessed through pyrolysis, vitrinite reflectance and 1D basin modeling. Results show the source rocks of Thebes and Brown Limestone formations exhibit favorable to excellent source rock characteristics with Type I–II kerogen and have the capacity to generate oil. Conversely, the source rocks of the Matulla Formation show fair to good source rock characteristics with Type II–III kerogen and have the capacity to produce both oil and gas. Thermal maturity shows the source rocks are at an immature stage. A 1D basin model is constructed for Well G-9 to simulate multi-tectonic episodes, burial events, and the history of thermal maturity. Sedimentation rates of Cretaceous to Eocene deposits are characterized by a low burial rate, which contrasts with the high burial and sedimentation rates for Miocene and post Miocene (Pliocene–Recent) strata. Overall, the South Geisum oilfield petroleum system is found to be immature based on integration of source rock evaluation and petroleum basin modelling.

The objective of this study is to test the influence of some key input parameters in basin modelling and to evaluate the resultant effect of varying these parameters on the model. 3D basin modelling and petroleum system analysis of the northern North Sea has been carried out using the PETROMOD software. The model was calibrated using well 34/8-7 in the Visund field. Different input parameters such as heat flow, source rock properties, fault properties, paleo water depth, source rock kinetics, migration methods and different erosion scenarios have been varied and their effects on the model assessed. The effect of the various input parameters has been assessed in terms of hydrocarbon volumes in the Kvitebjørn and Visund fields, source rock maturity, transformation ratios, hydrocarbon saturations and the time hydrocarbon generation began in the Draupne and Heather Formation source rocks. Increase in heat flow increases source rock maturity, the start of hydrocarbon generation, transformation ratios and results in the generation of a lot more gas than oil. Hydrocarbon generation starts at shallower depths with higher heat flow. Increasing Total Organic Content (TOC) and Hydrogen Index (HI) generally results in increase in the volume of hydrocarbons generated. The increase in HI, however, results in the generation of a lot more oil than gas. High TOC and HI also increase the hydrocarbon saturations in the source rock. Increasing Paleo Water Depth (PWD) has a marginal effect on the model. It increases the volume of oil and decreases the volume of gas marginally. Varying the PWD has no significant effect on source rock maturity, transformation ratios and hydrocarbon saturations. Opening the fault planes resulted in an increase in the volume of hydrocarbons generated. The increase was more evident in the volume of oil than gas. This increase in volumes is a consequence of additional migration pathways created by the faults. Varying the erosion thickness of the Draupne Formation did not have any effect on the model.

The role of the Middle-Upper Miocene source rocks in the Late Neogene petroleum system of the Pannonian Basin is undoubtedly significant, but it is not entirely understood. Only a few general publications exist that describe these sediments and their importance. We have focused on understanding the Neogene tectono-stratigraphic development and petroleum systems of these relatively small syn-rift grabens in southern Hungary. We have developed a workflow for organic geochemical, seismic, and facies interpretation; basin subsidence; and 3D basin modeling to better understand the Miocene-Pliocene-age petroleum system in a [Formula: see text] study area. This area fully covers two small-scale (less than [Formula: see text] size each) troughs filled by syn-rift and postrift deposits in large thickness with significantly different structural histories. During our investigation, six source rock beds were identified and built into the model. Thousands of meters of Lower Miocene, (Karpatian age) sediment accumulated in a “pull-apart,” but later structurally inverted Kiskunhalas Trough in the south, where four moderate- to good-quality (2 wt% estimated original total organic carbon [TOC], 200 HI), dominantly gas-prone, immature to wet gas mature source rock beds were identified. In the overlying Middle Miocene (Badenian age) sediments, generally good quality (2 wt% estimated original [TOC], 300–500 HI, type II and II-S), oil-prone, dominantly oil mature source bed was identified. This layer, as the regional Miocene source rock, is mainly responsible for the known hydrocarbon (HC) accumulations. The 3D basin and petroleum system modeling helped us understand the HC migration into the already-discovered fields as well as identify possible future exploration objects.

Organic geochemical signals of Paleozoic rocks in the southern Tethys, Siwa basin, Egypt: Implications for source rock characterization and petroleum system

3D stratigraphic, structural, thermal and migration modelling has become an essential part of petroleum systems analysis for passive margins, especially if complex 3D facies patterns and extensive volcanic activity are observed. A better understanding of such underexplored offshore areas requires a refined 3D basin modelling approach, with the implementation of realistically sized volcanic intrusions, source rocks and reservoir intervals. In this study, an integrated modelling workflow based on a Great Australian Bight case study has been applied. The 244800-km2 3D model integrates well data, marine surveys, 3D stratigraphic forward modelling and 3D basin modelling to better predict the effects of 3D facies variations and heat flow anomalies on the determination of the source rock-enriched intervals, the source rock maturity history and the hydrocarbon migration pathways. Plausible sedimentary sequences have been estimated using a stratigraphic forward model constrained by the limited available well data, seismic interpretation and published tectonic basin history. We also took into account other datasets to produce a thermal history model, such as the location of known volcanic intrusion, volcanic seamounts, bottom hole temperature and surface heat flow measurements. Such basin modelling integrates multiple datatypes acquired in the same basin and provides an ideal platform for testing hypotheses on source rock richness or kinetics, as well as on hydrocarbon migration timing and pathways evolution. The model is flexible, can be easily refined around specific zones of interest and can be updated as new datasets, such as new seismic interpretations and data from new sampling campaigns and wells, are acquired.

Hendijan oil field is located in north of Persian Gulf and is producing oil from 3 different reservoirs. Geochemical studies of candidate source rocks have revealed that four interval of source rocks exist in this region that could generate hydrocarbons. These formations include: Pabdeh (Tertiary), Kazhdumi (Albian), Garau (L. Certaceous) and Sargelu (M. Jurrasic). Oil-Source rock correlations are based chemical properties, biomarkers, C13 Isotope and other geochemical indices. Geochemical analyses done in Hendijan oil field have shown that Kazhdumi and Garau formations are the most important source rocks in the region. Pabdeh formation is excluded from possible source rocks due to its low maturity. No geochemical analyses have done on Sargelu formation. Different geochemical analyses including GC, GC-MS and Isotope (Carbon and Sulfur) have done on 3 oil samples from Asmari (Tertiary), Sarvak (M. Cretaceous) and Nahr Umr (E. Cretaceous) reservoirs. In addition, burial and thermal history modeling was performed to determine timing of hydrocarbon generation in the candidate source rocks in studied field. Geology and sequence Stratigraphy analysis of borehole data including drill-cuttings provided fundamental constrains for burial history reconstruction. One-dimensional model of thermal evolution were derived from the burial history and calibrated with Vitrinite reflectance, thermal conductivity, surface and bottom-hole temperature measurements, as well as with paleoclimate data. Regarding geochemical analysis on several oil samples, all the reservoirs have been charged by one source rock. Biomarkers and isotope data indicate that Kazhdumi Formation correlates best with oil samples. In addition to geochemical analysis, 1D petroleum system modeling shows that Kazhdumi and Garau source rocks reached oil generation window in 3 and 4 MY ago respectively and both of them are still in oil generation window. But lack of Oleanane biomarker in analyzed oil samples and low TOC content of Pabdeh formation confirms no charge of reservoirs by tertiary candidate source rock (Pabdeh).

Petroleum system assessment of the Beni Suef Basin, Western Desert, Egypt

The main factors of the developmental environment of marine source rocks in continental margin basins have their specificality. This realization, in return, has led to the recognition that the developmental environment and pattern of marine source rocks, especially for the source rocks in continental margin basins, are still controversial or poorly understood. Through the analysis of the trace elements and maceral data, the developmental environment of Miocene marine source rocks in the Qiongdongnan Basin is reconstructed, and the developmental patterns of the Miocene marine source rocks are established. This paper attempts to reveal the hydrocarbon potential of the Miocene marine source rocks in different environment and speculate the quality of source rocks in bathyal region of the continental slope without exploratory well. Our results highlight the palaeoenvironment and its control on the formation of Miocene marine source rocks in the Qiongdongnan Basin of the northern South China Sea and speculate the hydrocarbon potential of the source rocks in the bathyal region. This study provides a window for better understanding the main factors influencing the marine source rocks in the continental margin basins, including productivity, preservation conditions, and the input of terrestrial organic matter.

The Mohe Formation is one of the important source rocks for oil-gas and gas hydrates in the Mohe Basin. In this paper, mudstone from cores of the M-1 and M-3 wells and argillite from cores of the MK-2 well of the Mohe Basin were studied. The depositional environment, organic matter source, thermal maturity, kerogen type, and hydrocarbon generation potential of the core samples were determined using organic and inorganic geochemistry. The dual sources of organic matter were terrestrial plants and aquatic organisms. The organic matter was deposited in a reducing lacustrine environment. The lake water salinity was higher when argillite was deposited. The late stage of the sedimentary filling of the lacustrine basin was characterized by high sulfate contents. The source rocks primarily contained Type II2–III kerogen. The present-day thermal maturity parameters reveal that the organic matter of the Mohe Formation is mature to overmature, indicating that this unit is capable of generating gas condensate and dry gas. In addition, we compared the organic geochemistry characteristics of mudstone and argillite. The results indicate that TOC, S1 + S2, and HI are lower in argillite than in mudstone. Although the biomarker maturity parameters cannot reflect the thermal evolution of the source rocks, they reflect the source of the organic matter and the depositional environment. The results provide important constraints for the evaluation of the hydrocarbon potential of lacustrine source rocks of the Mohe Formation from the Upper Jurassic and for the location of petroleum resources in the Mohe Basin.

Petroleum source-rock potential of the Piranj oil field, Zagros basin

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.

Clay mineral diagenesis and source rock assessment in the Bornu Basin, Nigeria: Implications for thermal maturity and source rock potential

A collection of 14 crude oil samples representing 13 giant oil fields from the prerift and synrift reservoirs of the Gulf of Suez province were analyzed for C7 light hydrocarbons. The light hydrocarbon parameters C7 star plot diagrams in conjunction with the biomarker characteristics differences were used to distinguish the Gulf of Suez into two oil groups, the prerift and synrift oils, which are predominantly source related and maturity dependent. The biomarker properties indicate that the prerift oils exhibit oleanane index 23%, while the synrift oils are characterized by relatively higher oleanane index around 30% and low gammacerane index values <10%. The prerift oils are correlated with the Upper Cretaceous Brown Limestone and Sudr chalk formations, which are possibly representative of the carbonate-rich marine source rocks of type II kerogen. The synrift oils are correlated with Lower Miocene Rudeis siliciclastic source rocks of mixed types II-III kerogen. The prerift and synrift source rocks entered the oil generation window at vitrinite reflectance between 0.7 to 0.9 Ro%, equivalent to formation temperature at 110°C and 125°C, which permits the expulsion of mature crude oils to reservoir rocks according to their stratigraphic and structural relations. The higher sterane maturity parameters, i.e., diasterane index, C 29 ααα20S/(S + R), and C 29 αββ/(αββ + aaa), of the prerift oils imply a generation from carbonate rich marine source rocks at a very high maturity level in comparison with the relatively mature siliciclastic source rocks that generated the synrift oils in the Gulf of Suez rift basin.

Organic geochemistry, distribution and hydrocarbon potential of source rocks in the Paleocene, Lishui Sag, East China Sea Shelf Basin

The influence of facies and depositional environment on the occurrence and distribution of carbazoles and benzocarbazoles in crude oils: a case study from the Gulf of Suez, Egypt