This paper summarizes the results of Rock-Eval pyrolysis data of 43 shale samples collected from the latest Ordovician – earliest Silurian (Tanezzuft Formation) interval in the CASP JA-2 well at Jebel Asba on the eastern margin of the Kufra Basin, SE Libya. The results are supported by analysis of cuttings samples from an earlier well of uncertain origin nearby, referred to here as the UN-REMSA well. The Tanezzuft Formation succession encountered in the JA-2 well can be divided into three intervals based on Rock-Eval pyrolysis data. Shales in the shallowest interval (20 – 46.5 m depth) are altered probably by weathering and lack significant amounts of organic matter. Total organic carbon (TOC) contents of shales from the intermediate interval (46.5 – 68.5 m depth) vary between 0.19 and 0.75 wt%. Most samples in this interval have very limited source rock potential although a few have Hydrogen Index (HI) values up to 378 mg S2/g TOC. Tmax values of 422 – 426°C indicate the organic matter is immature. Shales from the deepest interval (68.5 – 73.9 m depth) are diagenetically altered, perhaps by fluids flowing along a nearby fault or along the contact between the Tanezzuft Formation and the underlying Mamuniyat Formation and apparently lack any organic matter. Cuttings samples from the UN-REMSA well have TOC contents of 0.48–0.87 wt%, HI values of 242–252 mg S2/g TOC, and Tmax values of 421–425°C. These results offer little support for the presence of the basal Silurian (Tanezzuft Formation) source rock which is prolific elsewhere in SW Libya and eastern Algeria and, together with the overall immaturity of the equivalent section, reduces the probability of finding major oil reserves in the eastern part of the Kufra Basin.
]]>In the Barapukuria and Dighipara coal basins, NW Bangladesh, the Basement Complex is overlain by the coal-bearing Permian Gondwana Group. In the present study, 36 core samples collected from five boreholes in these two basins were analysed using organic geochemical and organic petrological methods. Based on the results of biomarker analyses (TIC, m/z 191 and m/z 217 fragmentograms) and maceral composition (proportions of vitrinite, liptinite, inertinite), three organic facies were identified: coals, carbargillites and mudstones. Together with other evidence, cross-plots of HI versus Tmax and Pr/nC17 versus Ph/nC18 indicate that the coals, as expected, were dominated by terrestrial organic matter (OM). The carbargillites contained a mixture of terrestrial and probable Type II aquatic OM, and the mudstones contained mostly terrestrial OM. Accordingly the coals, carbargillites and mudstones are interpreted to have been deposited in swamp-dominated environments in a delta-plain setting which was subject, in the case of carbargillites, to periodic flooding. Suboxic conditions were indicated by very high Pr/Ph ratios and a high content of inertinite macerals.
All the samples analysed were immature or early mature for hydrocarbon generation, as indicated by mean vitrinite reflectance (%Ro) of 0.60–0.81%, Rock-Eval Tmax of 430–439°C, and biomarker ratios (hopane C32 22S/(22S+22R)) of 0.57–0.60. Carbargillites showed potential for both liquid and gaseous hydrocarbon generation; coals were mainly gas-prone with minor liquid hydrocarbon potential; and mudstones were dominantly gas-prone. The oil-prone nature of the samples was attributed to the presence of resinite, cutinite, bituminite and fluorescent vitrinite. The presence of exsudatinite within crack networks, solid bitumen and oil droplets as well as bituminite at early oil-window maturities suggests that the organic matter may have expelled some hydrocarbons.
The Lower Palaeozoic succession in SE Poland and West Ukraine has source rock potential, particularly the Ordovician and Silurian which contain oil-prone Type II kerogen. The thermal maturity of these units ranges from early to late-phase oil window (locally up to gas window). Within the Mesozoic succession, source rock potential is highest in the Middle Jurassic which has TOC of up to 26 wt% and a genetic potential of up to 39 mg/g of rock, with organic matter dominated by gas-prone Type III kerogen. In SE Poland, the organic matter in this unit is generally immature, whereas maturities in West Ukraine are sufficient for hydrocarbon generation to occur.
Modelling of hydrocarbon generation suggested that petroleum in Lower Palaeozoic source rocks began to be generated in the Early Carboniferous. Peak generation took place from the late Visean to the early Namurian, and terminated either as a result of source rock depletion or Variscian inversion. Expelled hydrocarbons migrated during post-Carboniferous and Mesozoic uplift. Middle Jurassic source rocks in SE Poland have only reached the early oil window. Higher thermal maturities in the Ukraine resulted in hydrocarbon generation and expulsion. This took place after Miocene burial and maturation.
A number of small hydrocarbon accumulations occur in Mesozoic reservoirs in SE Poland / West Ukraine, and hydrocarbons have migrated from Cambrian and Ordovician source rocks. However, the prospectivity of the study area is reduced as a result of phases of uplift and intense erosion which allowed hydrocarbons to escape from structural traps.
Downhole formation pressure data can be difficult to obtain and the quality of the data produced varies significantly with age, tool type and geology. Furthermore, even if a new well is characterised effectively and high quality data obtained, the radius of investigation is small compared to the size of the area typically being assessed. Nevertheless, understanding the subsurface formation pressure system is a prerequisite for any basin or reservoir evaluation during exploration, appraisal and production. It requires integrating pressure and subsurface data from spatially disparate wells, and requires direct, quantitative comparison of historical and contemporary data-sets. This comparison needs to be objective, repeatable and robust.
This paper describes a qualitative system for systematically and objectively comparing all types of formation pressure measurements to provide a basis for a qualitative interpretation of the subsurface formation pressure system. The application of the system consists of a set of questions designed to assess the quality and quantity of formation pressure data available from information in the well completion report. Each question defines quantitative limits for key pressure test parameters that determine the quality class of the formation pressure of that test. The questions require a ‘yes’ or ‘no’ answer, and the cumulative set of answers results in a code that reflects the overall quality of the data. The resulting set of codes can be used directly or can be further subdivided into a set of five reliability classes.
The system does not assess the accuracy of an individual pressure test, but provides a context for meaningful comparisons to be made of formation pressure data acquired under spatially and temporally disparate conditions. This allows for an interpretation of the data to be made that accounts for the variable reliability of individual data points. The system is generic and can be applied to any basin, onshore or offshore. It is suitable for field-scale studies up to basin-scale studies and can be applied to producing or non-producing data. This paper outlines the underlying principles and the methodology required to apply the quality code system. It includes examples of how application of both the quality codes and the reliability classes can simplify the interpretation of a scattered data-set and provide tools to effectively communicate the results.
Tar residues (“tarballs”) occur frequently on the SE coast of the Paria Peninsula, NE Venezuela. This paper reports on tarballs recovered from approximately 14 km of shoreline during monthly sampling over a two-year period ending in April, 2011. The tarballs were analysed geochemically and results show that more than 70% of them could be included within a single compositional group on the basis of their physical and organoleptic properties. The tarballs were fingerprinted using biomarkers (hopanes, steranes, alkanes, aromatic steroids, phenanthrenes and dibenzothiophenes) by gas chromatography and gas chromatography – mass spectrometry. Sulphur and trace element contents were also determined. These analyses indicate that the tarballs do not have an anthropogenic origin, but that they probably originated from petroleum generated by argillaceous limestones in the Turonian – Campanian Naparima Hill Formation. This formation includes marls and organic-rich shales and limestones, and is an important source rock at oilfields in Trinidad and the southern Gulf of Paria. In the southern part of the Gulf, petroleum escapes from Neogene reservoirs to the seafloor via natural seepages associated with the Los Bajos and other fault systems. It is inferred that the petroleum is then transported by wind and tidal currents to the coast of the SE Paria Peninsula where it strands as tarballs. The geochemistry of the tarballs collected is discussed to investigate their source.
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