Petrophysical and geochemical characterization of potential unconventional gas shale reservoirs in the southern Karoo Basin, South Africa

Abstract

Ten Permian black shale samples from the southern Karoo Basin (South Africa) were investigated regarding their shale gas generation potential, storage capacity and transport properties. Samples originate from a 671 m deep borehole (KZF-1), comprising the Collingham, Whitehill and Prince Albert Formations of the lower Ecca Group (Karoo Supergroup).Based on organic geochemical analyses (TOC, TS, Rock-Eval pyrolysis and vitrinite reflectance), the Whitehill Formation was deposited under anoxic marine depositional conditions and has reached high thermal maturity. The Collingham and Prince Albert Formation were deposited under suboxic to oxic conditions. The amount of total organic carbon (TOC) across all formations ranges between 0.5 and 6.1 wt.-%, and was highest for the Whitehill Formation samples. The organic matter in the different lithologies are highly overmature with vitrinite reflectance values around 4.0% VRr, and almost absent Rock-Eval S1 and S2 peaks. Peak gas generation probably occurred due to tectono-metamorphic overprinting during the Cape Orogeny (240–270 Ma).Permeability ranges from 10−22 to 10−19 m2 (1–100 nDarcy) and is lowest for the Whitehill and Prince Albert Formation. Porosity at ambient stress ranges from 4.1 to 6.3% and is highest within the Whitehill Formation. Neither permeability nor porosity show significant dependence upon induced stress. Excess sorption capacity is highest for the Whitehill Formation, nexcess10MPa ranging from 0.079 to 0.172 mmol/g. For the depth interval investigated here (671 m), the estimated total gas storage capacity (sum of free and adsorbed gas phase) of the Whitehill Formation is approximately 400 to 465 mol CH4 per m3 rock. Using a simple one-dimensional diffusion model, we calculated the potentially remaining stored amount of gas. In a modelled best-case scenario, it is assumed that dissipation of the gas only occurs through the side boundaries (fractured dykes system) whereas top and bottom are assumed to act as perfect seals. Assuming a fracture distance of 1000 m, the model predicts complete gas dissipation to take place within a period of 10−2 to 102 Ma. Regarding the peak gas generation at 240–270 Ma, the remaining shale gas potential is therefore considered extremely low.