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Marine Organic Matter (marine + organic_matter)
Selected AbstractsSOURCE ROCK EVALUATION AND GEOCHEMISTRY OF CONDENSATES AND NATURAL GASES, OFFSHORE NILE DELTA, EGYPTJOURNAL OF PETROLEUM GEOLOGY, Issue 2 2003L. M. Sharaf Geochemical analyses of mudstones from wells in the NE offshore Nile Delta suggest that the Early Miocene Qantara Formation has "good" potential to generate hydrocarbons at the studied locations. Its generating capability and oil-proneness increase northwards, towards areas where better organic-matter preservation and a greater contribution from marine source material can be expected. By contrast, the Middle Miocene Sidi Salem Formation has "poor to fair" potential to generate mixed gas and oil, while the overlying Wakar and Kafr El Sheikh Formations have "poor" capability to generate gas with minor oil. Based on pyrolysis Tmax and thermal alteration index assessments, the Wakar and Kafr El Sheikh Formations are immature in the study area. The Sidi Salem and Qantara Formations are immature in the southern part of the study area, but are within the oil window in the north, around well Temsah-4. Biomarker distributions based on GC-MS analyses of two condensate samples from the Wakar and Sidi Salem Formations indicate that hydrocarbons are derived from siliciclastic source rocks containing significant terrestrial material and limited marine organic matter. The condensates were generated during early maturation of Type III kerogen from deeper and more mature source rocks than those encountered in the drilled wells. Geochemical and isotopic data from natural gas produced from the Kafr El Sheikh Formation suggest mixed biogenic and thermogenic sources. [source] CRETACEOUS CARBONATES IN THE ADIYAMAN REGION, SE TURKEY: AN ASSESSMENT OF BURIAL HISTORY AND SOURCE-ROCK POTENTIALJOURNAL OF PETROLEUM GEOLOGY, Issue 1 2000I. H. Demirel The burial history and source-rock potential of Cretaceous carbonates in the Adiyaman region of SE Turkey have been investigated. The carbonates belong to the Aptian-Campanian Mardin Group and the overlying Karabogaz Formation. The stratigraphy of these carbonates at four well locations was recorded. At each well, the carbonate succession was found to be incomplete, and important unconformities were present indicating periods of non-deposition and/or erosion. These unconformities are of variable extent. When combined with the effects of rapid subsidence and sedimentation which took place in the SW of the Adiyaman region during end-Cretaceous foredeep development, they have resulted in variations in the carbonates' present-day burial depths, thereby influencing the regional pattern of source-rock maturation and the timing of oil generation. Burial history curves indicate that the carbonates' maturity increases from SW to NE, towards the Late Cretaceous thrust belt. Predicted levels of maturity for the Mardin Group are consistent with measured geochemical data from three of the wells in the study area (the exception being well Karadag-1). Three potential source-rock intervals of Cretaceous age have been identified. Two of these units , the Derdere and Karababa Formations of the Mardin Group , are composed of shallow-water carbonates which were deposited on the northern margin of the Arabian Platform. The third source-rock unit, the overlying Karabogaz Formation, is composed of pelagic carbonates which were deposited during a regional transgression. These potential source-rock intervals contain marine organic matter dominated by Type II kerogen. Total organic carbon contents range from 0.5 to 2.9 %. Time-temperature analyses indicate that the Mardin Group carbonates are immature to marginally mature at well locations in the SW of the study area, and are mature at western and NE well locations. The onset of oil generation in these Cretaceous source rocks took place between the middle Eocene (48 million yrs ago) and the Oligocene (28 million yrs ago). [source] Geochemistry, Petrography and Spectroscopy of Organic Matter of Clay-Associated Kerogen of Ypresian Series: Gafsa-Metlaoui Phosphatic Basin, TunisiaRESOURCE GEOLOGY, Issue 4 2008Mongi Felhi Abstract This work presents geochemical characterization of isolated kerogen out of clay fraction using petrography studies, infrared absorption and solid state 13C nuclear magnetic resonance (NMR) spectroscopy, with N -alkane distributions of saturated hydrocarbon. Mineralogical study of clay mineral associations was carried out using X-ray diffraction (XRD), on Ypresian phosphatic series from Gafsa-Metlaoui basin, Tunisia. The XRD data indicate that smectite, palygorskite and sepiolite are the prevalent clay minerals in the selected samples. In this clay mineral association, the N -alkane (m/z = 57) distribution indicates that the marine organic matter is plankton and bacterial in origin. The kerogens observed on transmitted light microscopy, however, appear to be totally amorphous organic matter, without any appearance of biological form. The orange gel-like amorphous organic matter with distinct edges and homogenous texture is consistent with a high degree of aliphaticity. This material has relatively intense CH2 and CH3 infrared bands in 13C NMR peaks. This aliphatic character is related to bacterial origin. Brown amorphous organic matter with diffuse edges has a lower aliphatic character than the previous kerogen, deduced from relatively low CH2 and CH3 infrared and 13C NMR band intensities. [source] North-south Differentiation of the Hydrocarbon Accumulation Pattern of Carbonate Reservoirs in the Yingmaili Low Uplift, Tarim Basin, Northwest ChinaACTA GEOLOGICA SINICA (ENGLISH EDITION), Issue 3 2008Lü Xiuxiang Abstract: By analyzing the characteristics of development, structural evolution and reservoir beds of the residual carbonate strata, this study shows that the residual carbonate strata in the Yingmaili low uplift are favorable oil and gas accumulation series in the Tabei (northern Tarim uplift) uplift. There are different patterns of hydrocarbon accumulation on the northern and southern slopes of the Yingmaili low uplift. The north-south differentiation of oil reservoirs were caused by different lithologies of the residual carbonate strata and the key constraints on the development of the reservoir beds. The Mesozoic terrestrial organic matter in the Kuqa depression and the Palaeozoic marine organic matter in the Manjiaer sag of the Northern depression are the major hydrocarbon source rocks for the northern slope and southern slope respectively. The hydrocarbon accumulation on the northern and southern slopes is controlled by differences in maturity and thermal evolution history of these two kinds of organic matter. On the southern slope, the oil accumulation formed in the early stage was destroyed completely, and the period from the late Hercynian to the Himalayian is the most important time for hydrocarbon accumulation. However, the time of hydrocarbon accumulation on the northern slope began 5 Ma B.P. Carbonate inner buried anticlines reservoirs are present on the southern slope, while weathered crust and paleo-buried hill karst carbonate reservoirs are present on the northern slope. The northern and southern slopes had different controlling factors of hydrocarbon accumulation respectively. Fracture growth in the reservoir beds is the most important controlling factor on the southern slope; while hydrocarbon accumulation on the northern slope is controlled by weathered crust and cap rock. [source] | ||||||||||