Advanced Organic Geochemical Studies on the Petroleum Systems of the Nile Delta and Red Sea Basins, Egypt - Ahmed, Ahmed Khairy Ali (2025)
The Nile Delta is a significant petroleum province in Egypt and the eastern Mediterranean. However, the origin of discovered hydrocarbons, particularly in the onshore part of the basin, was not thoroughly studied, and source-reservoir relationships remain unclear. Previous studies focused mainly on routine source rock assessment using TOC and Rock-Eval pyrolysis data, with limited investigations of the biomarker, isotopic, and molecular geochemical characteristics of the disseminated organic matter. Consequently, a more comprehensive source-reservoir correlation is essential for future exploration success. This study assesses potential source rocks from the Nile Delta Basin and examines the discovered hydrocarbons to better understand source-reservoir relationships with a greater focus on the onshore part of the basin, which received little attention. A comprehensive geochemical evaluation of Oligocene-Pliocene source rocks and discovered hydrocarbons from the onshore Nile Delta was conducted. Molecular and isotopic compositions, biomarker distributions, and multivariate statistical techniques (chemometrics) were applied to classify hydrocarbons into genetic families and conduct oil-source correlations. The quantity, quality, thermal maturity, sources, and depositional palaeoenvironment of the disseminated organic matter were also investigated. Geochemical signatures of onshore Nile Delta condensates suggest non-marine waxy oils derived from clay-rich source rocks dominated by Type-III terrigenous organic matter, deposited in oxic fluvio-deltaic settings. The molecular and isotopic results indicate that Oligocene-Miocene natural gases are wet-thermogenic, generated by secondary cracking of associated oils derived from Type-III, Type-II/III, or Type-II kerogen. The condensate and associated gas samples from Oligocene pay zones have different geochemical signatures than those from Miocene reservoirs, suggesting derivation from different source rocks with variable levels of thermal maturity or the presence of multiple charge systems from a common source in the onshore Nile Delta. Oligocene–Pliocene potential source rocks in onshore Nile Delta exhibit fair to good organic richness (TOC ~1 wt.%) and are predominantly gas-prone, containing Type-III kerogen with minor contributions from Type-II/III and Type-IV kerogens. Molecular and biomarker results indicate mixed organic matter contributions from higher plants, algae, bacteria, and plankton, deposited under suboxic to anoxic nearshore marine or lacustrine environments. Isotopic and molecular compositions of Oligocene-Pliocene mud gases reflect gases with complex origins and mixing histories, ranging from primary microbial to pure thermogenic, with pre-Miocene intervals dominated by thermogenic processes. Chemometric analyses reveal no definitive correlation between Miocene-Pliocene rocks and condensates or oils in the onshore Nile Delta, implying that deeper pre-Miocene rocks are the most probable source for hydrocarbons in the onshore Nile Delta. However, Cretaceous-Eocene intervals examined in the western offshore Nile Delta primarily contain Type-II marine-algal organic matter and show no similarity to the discovered condensates, based on n-alkane and isoprenoid ratios. Unlike the Gulf of Suez and Western Desert petroleum provinces, the Red Sea Basin remains underexplored in Egypt, with limited understanding of its petroleum systems. To investigate the effect of pressure on hydrocarbon generation from Type-I kerogen source rocks, high water-pressure pyrolysis experiments were conducted on an immature Type-I kerogen oil shale sample from the Duwi Formation, Red Sea Basin. The sample was pyrolysed under anhydrous, low-pressure hydrous (110–160 bar), and high water-pressure (500–900 bar) conditions at 320 °C (end of bitumen generation) and 350 °C (oil-generation window) for 6 and 24 h, respectively, contributing to a broader understanding of Type-I kerogen source rocks and how pressure in geological basins affects petroleum generation from these rocks. Results indicate that high water pressure retards oil, gas, and bitumen generation from Type-I kerogen source rocks, with oil generation being most affected. Compared to previously studied Type-II and Type-IIS kerogens, the retardation effect on oil generation from the Duwi Formation is more pronounced, while gas generation is less impacted at 350 °C. This is because high water pressure retards bitumen-to-oil conversion or oil expulsion from the rock, and the retained oil in the rock could be directly cracked into gas in the presence of clay minerals. This has significant implications for overpressured basins, where oil yields may be lower, while unconventional gas resources are likely to be more abundant. Consequently, the Duwi Formation should not only be regarded as an oil source but also as a potential candidate for unconventional gas exploration, particularly in overpressured areas of the Red Sea Basin. In addition to the effect of pressure on hydrocarbon generation, pyrolysis experiments on the Duwi Formation were utilised to examine the impact of pressure on biomarker evolution, which has not been studied previously. Results show that extracted bitumens exhibit higher maturity under anhydrous conditions than under low-pressure hydrous conditions, with more pronounced differences at 350 °C. Biomarker ratios further reveal that the extracted bitumen is consistently more mature than the corresponding generated oil, likely due to the catalytic effects of clay minerals on bitumen within the rock. In contrast, δ¹³C values were similar for extracted bitumen and the corresponding generated oil under identical experimental conditions. At 320 °C, C31‒C35 hopane isomerisation, Ts/Tm, Ts/H30, and C29Ts/H29 ratios consistently decreased with increasing pressure, while sterane ratios remained unaffected. However, at 350 °C, the dominant influence of temperature over pressure resulted in more complex and variable trends, suggesting that biomarker-based maturity assessments should be applied cautiously in overpressured basins. To further investigate the hydrocarbon potential of the Duwi Formation in the underexplored Red Sea Basin, chemometric analysis was conducted on pyrolysis-generated oils and natural oils from the Gulf of Suez. The results indicate that artificially generated oils and South Malak-1 oils from southwestern onshore Gulf of Suez are quite different, and both groups differ significantly from other natural oils. This similarity between 350 °C and South Malak-1 oils suggests that the Duwi Formation could be a key petroleum source in the underexplored Red Sea Basin when considering mixing and migration effects under natural conditions. This study provides valuable insights into the petroleum systems of the Nile Delta and Red Sea basins, improving the understanding of source-reservoir relationships. Moreover, it enhances the understanding of how high pressure affects biomarker evolution and petroleum generation from Type-I kerogen source rocks in geological basins. These findings offer valuable implications for petroleum exploration and biomarker-based maturity assessments, particularly in deep petroleum systems and overpressured basins.