ALBERT

Description: We report on geochemical and petrophysical properties of shales from the Prince Albert, Whitehill and Collingham Formations of the Lower Karoo Supergroup, near Jansenville in the Eastern Cape, close to the tectonic front of the Cape Fold Belt. Results are based on two boreholes sited on a southerly dipping limb of a shallowly plunging syncline. Structural, sedimentological, lithological, mineralogical, geochemical and petrophysical analyses provide detailed characteristics that have become the focus of interest for potential shale gas occurrences. The black shales of the Whitehill Formation are composed of quartz, illite, muscovite and chlorite, with lesser plagioclase and accessary pyrite. The Collingham Formation rocks have the largest proportion of quartz, which gives this formation a higher brittleness factor than that of the Prince Albert and Whitehill formations. Mercury porosimetry analyses yield average meso- and macroporosity values of 0.83% for black shales of the Whitehill Formation, confirming that these sediments are tightly packed. Layers of dolomite within the shales have porosities of 2.9%, and pores measuring 1.5 m wide. The black shales of the Whitehill Formation have an average total organic carbon (TOC) content of 4.5 weight % whereas the TOC content of shales in the Collingham and Prince Albert Formations is 〈1 weight %. The elemental composition and relatively higher 13 C and 15 N stable isotope values suggest that the Whitehill Formation was deposited under anoxic conditions, which led to the preservation of the mixed marine and terrestrial organic matter, whereas the Prince Albert and the Collingham Formations were deposited under oxidizing conditions. High maximum temperature values (Tmax average: 528°C), low overall hydrogen and oxygen index values (all from Rock Eval analyses) and high reflectance measurements on bitumen (BR o = 4%) characterise these sedimentary rocks as over mature. As a consequence, they display few hydrocarbon yields in pyrolysis and thermovaporization experiments, and offer a minor late-gas potential. The main characteristics of black shales in the study area indicate that their overmaturity with respect to hosting gas deposits is attributed to the tectono-metamorphic overprinting during the Cape Orogeny (ca. 250 Ma, Hälbich, 1993 ; Hansma et al., 2015 ). Rocks of the lower Karoo Supergroup outcropping within the area flanking the northern tectonic margin of the Cape Fold Belt therefore have limited potential for hosting shale gas deposits. This finding has implications for estimates of potential shale gas resources of the Karoo Basin.

Description: Locally increased porosity of carbonate reservoir rocks may result from acidic fluids that migrated as a pre-oil phase through the reservoir. Here, hydrogeochemical modelling, which is based on the principles of chemical equilibrium thermodynamics, is performed to test such a hypothetical concept. Despite the generic nature of the model, the modelling results give basic and quantitative insights into the mechanisms of calcite dissolution in carbonate reservoirs induced by migrating acidic and corrosive aqueous fluids. The hydrogeochemical batch modelling considers pre-oil-phase aqueous fluids that form by kerogen maturation in siliciclastic source rocks underlying the carbonate reservoir rocks. Although saturated with respect to calcite, migration of such fluids through the carbonate reservoir triggers continuous calcite dissolution along their migration path following a decreasing pressure and temperature regime. One-dimensional reactive transport modelling reveals that thermodynamically controlled chemical re-equilibration among pre-oil-phase fluids, calcite and CO 2(g) is the driving force for continuous calcite dissolution along this migration path. This reflects the increasing solubility of calcite in the system ‘pre-oil-phase fluids/calcite/CO 2(g) ’ with decreasing pressure and temperature. In consequence, such fluids can preserve their calcite-corrosive character, if they are exposed to continuously decreasing pressure and temperature along their migration path through the reservoir. Supplementary material: The modelling input files to ensure retraceability of our modelling approach and its results are available at http://www.geolsoc.org.uk/SUP18802 .