Egypt far Western Desert basins petroleum charge system as defined by oil chemistry and unmixing analysis

Abrams, Michael A.; Greb, Matthias D.; Collister, James W.; Thompson, Melissa

doi:10.1016/j.marpetgeo.2016.05.035

Cited by 23 publications

(8 citation statements)

References 23 publications

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“…As illustrated in Figure b using EICs (extracted ion chromatograms) of m / z = 71, 85, and 99, respectively, the condensate covers a wide range of n -alkanes series ( n -C 6 – n -C 29 ), in which lower-MW (molecular weight) compounds are more enriched and >C 20 compounds are of relatively low concentrations. Unlike the primary thermal condensates generated at high-maturity stages that are dominated by lower compounds before n -C 10 , the Yingnan2 condensate is more likely of secondary genesis.…”

Section: Resultsmentioning

confidence: 95%

Geochemical and Isotopic Evidence of the Genesis of a Condensate in the Eastern Tarim Basin, China: Implications for Petroleum Exploration

Zhang

Zhu

et al. 2019

Energy Fuels

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The exploration activities in the eastern Tarim Basin have been thwarted over the last decade after the discovery of several Jurassic gas condensate fields. In this study, the two-dimensional gas chromatography/time-of-flight mass spectrometry (GC × GC-TOFMS) and compound-specific carbon isotope analysis were performed on a Jurassic condensate (Yingnan2) and the associated gas to determine its genesis and the accumulation process in this area. The geochemical and isotopic features suggested that the condensate analyzed was a mixture of the Ordovician cracked paleo-oil with the Jurassic intact oil as evidenced by the concentrated diamondoids and ethanoadamantanes, the high gas generation temperature (∼195 °C), the heavy whole oil δ 13 C (−28.6‰), and the significant variation in the isotopic profile of n-alkanes. As the gas amount was constantly elevated due to both oil cracking and the mixing of the kerogen-cracking gas from the Cambrian source rock, phase transition occurred and thus formed the Yingnan2 secondary condensate. The constant mixing of nitrogen-rich kerogencracking gas complementarily caused an increase in the nitrogen gas content. The accumulation model of the condensate in the eastern Tarim Basin was proposed with consideration of the post-accumulation alterations including thermal cracking and mixing, which complicated the quality and distribution of subsurface petroleums. It was further speculated that abundant gas and condensate resources may be preserved in favorable reservoir-seal assemblages in this field.

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Section: Resultsmentioning

confidence: 95%

Geochemical and Isotopic Evidence of the Genesis of a Condensate in the Eastern Tarim Basin, China: Implications for Petroleum Exploration

Zhang

Zhu

et al. 2019

Energy Fuels

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“…Figure 3. Summary of the stratigraphy, description of the lithologies of the sedimentary sequences of the north Western Desert of Egypt and the depositional environment of the Cretaceous sequences (modified after Abrams et al, 2016). Figure 4.…”

Section: Resultsmentioning

confidence: 99%

Cretaceous (Hauterivian–Cenomanian) palaeoceanographic conditions in southeastern Tethys (Matruh Basin, Egypt): Implications for the Cretaceous climate of northeastern Gondwana

Deaf

Harding

Marshall

2020

Cretaceous Research

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Quantitative palynological, sedimentological, and geophysical data analyses of the Cretaceous Abu Tunis 1X well from the Matruh Basin, northwestern Egypt indicate deposition of four major alternating regressive-transgressive successions. Sedimentation was largely affected by the Tethyan 2nd order sea level changes, with minor overprints by regional tectonics. The Lower Cretaceous part of the succession shows regressive sequences of deltafront to delta-top (upper Hauterivian-lowermost upper Barremian), delta channel (upper Aptian-middle Albian), and distal deltaic (upper Albian) settings that were interrupted by transgressive inner-proximal middle shelf deposits (uppermost Barremian-middle Aptian). These sediment packages correspond to Tethyan sea level fall from the late Hauterivian to late Barremian, and to the early-middle Aptian long-term sea level high stand. The Tethyan late Aptian-middle Albian long-term (2nd order) sea level rise was masked by regional late Aptian-Albian uplift, which affected deposition of the later regressive sequence. The Cenomanian shows a change in depositional setting from a proximal inner shelf (lower Cenomanian) to a middle shelf setting (middle-upper Cenomanian), corresponding to the Tethyan long-term latest early-late Cenomanian sea level rise. We demonstrate that northeastern Gondwana (Egypt) experienced different climatic conditions from other parts of the Northern Gondwana Phytogeographic Province. The climate in Egypt shifted from less warm and more humid conditions of the Hauterivian-early Barremian to a warmer and drier climate during the late Barremian-middle Aptian, although never becoming as dry as western Northern Gondwana. Warmer and more humid conditions were reestablished during the late Aptian and became even more accentuated during the Albian-Cenomanian, in contrast to the warm and much drier climate of Northern Gondwana at that time. Turonian climatic conditions may have been less humid as a result of the breakup of the 2 Western Gondwanan supercontinent and the northeasterly drift of the African continent. The climatic conditions experienced in northeastern Gondwana developed through the early-mid Cretaceous as a result of changes in palaeolatitudinal position, variations in sea level, and shifts in the Intertropical Convergence Zone, which drove fluctuations between periods of warm humid and warm dry conditions.

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“…Thus, the S 2 parameter is regarded as a more informative indicator of the source rock potential when compared to the TOC parameter (Peters and Cassa, 1994;Dembicki, 2009Dembicki, , 2016. In the Abu Tunis 1X well, the deltaic deposits of the lower Kharita Formation from 7300-6450 ft (2225-1966 m) are characterized mainly by organic-rich intraformational shale intervals, and such lithologies have been identified as potential source rocks in previous studies, such as Shalaby et al (2011) and Abrams et al (2016), which comprise a net shale content of about 13.1 % (WEPCO, 1968). The lower Kharita Formation contains several shale intervals ranging in thickness from 1.5 to 9.8 m. These shale intervals show notable intraformational variations in organic richness, where they show good to very good/excellent hydrocarbon source potential (1.14-11.59, avg.…”

Section: Source Rock Potentialmentioning

confidence: 98%

Organic geochemical, palynofacies, and petrographic analyses examining the hydrocarbon potential of the Kharita Formation (Albian) in the Matruh Basin, northwestern Egypt

Deaf

Tahoun

Gentzis

et al. 2020

Marine and Petroleum Geology

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A recent study of selected samples from the Cretaceous (Albian) Kharita Formation of Egypt revealed very good to excellent source rock (SR) potential for six intraformational, organic-rich intervals. This work investigates the SR potential of the entire Kharita Formation across the Matruh Basin, using samples from two wells: the Abu Tunis 1X well from the central part of the basin, and the Siqeifa 1X well drilled on the eastern margin of the basin. More strongly reducing conditions were developed in the centre of the basin, and resulted in the deposition of more organic-rich shales by comparison to the less reducing conditions that prevailed on the eastern basin margin, where the shales contain less organic matter. Deltaic intraformational shales and carbonates in the Kharita Formation of Abu Tunis 1X constitute a significant 120 m net of the potential SR. The lower Kharita Formation contains 34 m net shale SR of good to very good/excellent organic richness, yielding values of 1.14-11.59 wt % total organic carbon (TOC). The organic matter has low Hydrogen Index (HI) values (184-389 mg HC/g TOC) and amorphous organic matter (AOM) and relatively high non-opaque phytoclast frequencies indicating mainly gas/oil-prone organofacies (kerogen types II/III). The upper Kharita is more important, containing 86 m net shale/carbonate SR that has fair to good organic richness (0.8-1.8 wt % TOC), and lower HI (126-250 mg HC/g TOC), a dominance of non-opaque phytoclasts, and subordinate AOM frequencies, which together indicate gas/oil-prone organofacies (kerogen Types III/II). In the Siqeifa 1X well, Kharita deltaic intraformational shales and shaley dolostones comprise 80 m net SR, which has mainly fair to good to less very good organic richness (0.8-2.1 wt % TOC), whilst low HI (93-220 mg HC/g TOC), dominance of non-opaque phytoclasts and subordinate AOM indicate gas-prone organofacies (kerogen Type III). A relative upward increase in deposition of lignite and coaly carbonaceous material supports a gas-prone organofacies. Whilst thermal maturity indices only point to immature to early mature (pre-to early oil-window) SRs in both the Abu Tunis 1X and Siqeifa 1X wells, hydrocarbon exploration focussing on this potential source rock may be justified in areas to the southeast of the Matruh Basin, where modelling indicates this unit may have reached the late mature oil-to main gas-generation window.

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Egypt far Western Desert basins petroleum charge system as defined by oil chemistry and unmixing analysis

Cited by 23 publications

References 23 publications

Geochemical and Isotopic Evidence of the Genesis of a Condensate in the Eastern Tarim Basin, China: Implications for Petroleum Exploration

Geochemical and Isotopic Evidence of the Genesis of a Condensate in the Eastern Tarim Basin, China: Implications for Petroleum Exploration

Cretaceous (Hauterivian–Cenomanian) palaeoceanographic conditions in southeastern Tethys (Matruh Basin, Egypt): Implications for the Cretaceous climate of northeastern Gondwana

Organic geochemical, palynofacies, and petrographic analyses examining the hydrocarbon potential of the Kharita Formation (Albian) in the Matruh Basin, northwestern Egypt

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