| dc.description.abstract | The use of integrated approach to evaluate reservoir rock quality and source rock potential is becoming increasingly important in petroleum geology. This approach was employed to unravel the reason for variable reservoir quality of sandstones and evaluation of source rock potential of shale intervals of Orange Basin, SW, South Africa. The data sets acquired for this study include 783.63 km digital 2D seismic lines cutting across the 5 blocks of the basin, digital wireline logs (gamma ray, resistivity, density and neutron), core (sidewall and core) and ditch cutting samples from 10 wells of interest. The digital seismic section and wireline logs were subjected to manual and computer interpretation using specialized softwares (FastTracker, PETREL 2008, and SMT 8.2). The wireline logs of the 10wells were broken to depositional sequences and systems tracts: lowstand, transgressive and highstand systems tracts. The seismic section was analysed for depositional sequences, systems tracts and structures. Growth faults that are listric and normal were found localized in the basin. The faults are flank faults, erestal faults as well as antithetic faults. Sandstone and shale samples were selected within the systems tracts for laboratory
analyses. The sidewall and core samples were subjected to petrographic thin section analysis, mineralogical analyses which include x-ray diffraction (XRD), scanning electron microscopy (SEM), energy dispersive spectroscopy (EDS), and stable carbon and oxygen isotopes geochemistry to determine the diagenetic alteration at deposition and post deposition in the basin. The shale samples were subjected to Roek-Eval pyrolysis and accelerated solvent extraction (ASE) prior to gas chromatographic (GC) and gas chromatographic-mass spectrometric (GC-MS) analyses of the rock extracts, in order to determine the provenance, type and thermal maturity of organic matter present in
sediments of the Orange Basin. The results revealed a complex diagenetic history of sandstones in this basin, which includes compaction, cementation/micritization, dissolution, silicification/overgrowth of quartz, and fracturing. The Eh-pH shows that the cements in the area of the basin under investigation were precipitated under weak acidic and slightly alkaline conditions. The 0 80 isotope values range from -1.648 to 10.054 %, -1.574 to 13.134 %, and -2.644 to 16.180 % in the LST, TST, and HST, respectively. While 03e isotope values range from
-25.667 to -12.44 %, -27.862 to -6.954% and -27.407 to -19.935 % in the LST, TST, and HST, respectively. The plot of 0180 versus 0J3e shows that the sediments were deposited in shallow marine temperate conditions. The consistency of abundance of 0J3e isotope across the stratigraphic sequences indicates that the burial diagenesis has no significant effect on geochemical pattern of occurrence of ()J3e isotope in the sandstones under investigation. The authigenic minerals precipitated blocked the grain interspaces and interlayers and with continued burial, compaction impeded the development of secondary porosity resulting in the poor reservoir quality. The origins of the cementing materials are both autochtonous and allochtonous. The Roek-Eval pyroysis and Toe results of the shale samples revealed that LST is
characterised by mainly marginally organic rich shale samples with a few organic rich rocks, variable organic matter types ranging from Type II to Type IV, and a few samples are thermally mature but have low organic matter quality. Four samples from two wells (A_Fl and a_AI) in the LST have good petroleum generative potential but not sufficiently mature for petroleum generation. TST is characterised with a few samples
being marginally organic rich with only one being organic rich, mainly Type III kerogen with few Type IV kerogen, and only a few samples are thermally mature that has low organic matter quality. HST is characterised by many marginally organic rich rock samples, mainly Type III and a few mixed Type IIIIII kerogen, and only a few samples are thermally mature. The results of this study show that the LST has the best prospect in terms of petroleum generation potential, followed by HST and TST has least petroleum generation potential. The study also reveals that limited petroleum source rocks exist, which are also impacted by low thermal maturity levels. The basin is more gas prone than oil The shale samples were further analysed by Rock-Eval-Pyrolysis and for n-alkanes, aliphatic isoprenoid hydrocarbons and biomarkers (steranes and hopanes) by gas 2 chromatography (GC) and gas chromatography-mass spectrometry (GC-MS). For most of the shale samples from the different stratigraphic sequences from Aptian to Campanian age Roek-Eval data (hydrogen (HI) and oxygen index (Ol)) and biomarker parameters (oleanane/hopane ratio, proportions of steranes, pristaneln-heptadecane vs. phytanelnoctadecane) point to mainly Typ III terrestrial organic matter. Only a few samples of Turonian age reveal a higher proportion of marine organic matter being classified as Typ
IIIIII or Typ II. Biomarker parameters also suggest that the samples are deposited under suboxic to oxic environmental conditions. Roek-Eval data and biomarker maturity parameters assign for most of the samples a maturity level at the beginning of the oil window with some more mature samples of Aptian, Albian and Cenomanian age. The hydrocarbon generation potential is for most of the samples low as indicated by the S2/S3 ratio and HI values, exceptions are samples from Turonian and Aptian age | en_US |
