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 δ¹³C and δ¹⁵N 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.

-Ressources de gaz non conventionnels dans le Paléozoïque de l'Europe Centrale-Alors que l'extraction du gaz naturel des gisements non conventionnels a fortement augmenté ces dernières dizaines d'années, un large potentiel de ressources reste inexploré dans les couches paléozoïques de l'Europe Centrale. Cet article présente, pour cette région, quelques aspects importants de la géologie des grès de faible perméabilité (tight gas sands), des gaz de schiste (gas shales) et du gaz de houille (coalbed methane, CBM). Les grès de faible perméabilité se trouvent surtout parmi les couches permiennes (Rotliegend) aux Pays-Bas et dans le nord de l'Allemagne, mais aussi dans les couches du Carbonifère supérieur. La production est déjà active dans quelques-uns de ces réservoirs. Pour l'avenir, le développement dépendra principalement de l'amélioration de la compréhension du gaz en place et de la distribution régionale de la porosité et la perméabilité qui, d'ailleurs, dépendent du faciès lithologique et la diagénèse. La recherche de gaz dans les roches argileuses, par contre, vient juste de commencer. Les roches argileuses mésozoïques dans le sud du bassin de Basse-Saxe (Lower Saxony Basin) sont des objets d'exploration prioritaire à cause de leur épaisseur, de leur maturité et de leur teneur en matière organique. Mais il existe d'autres séries intéressantes dans le carbonifère inférieur et des couches plus anciennes. Actuellement, un projet de recherche international vise à acquérir des données géologiques sur ces systèmes. La recherche du gaz de houille (CBM) a commencé dans la bassin de la Ruhr il y a une vingtaine d'années, mais avec un succès très limité à cause de faibles débits de gaz. En revanche, le captage de grisou des mines de charbon abandonnées a fourni de considérables quantités de gaz. De par la multitude des filons houillers et des conditions de maturité et de teneurs en gaz favorables, il existe dans cette région un potentiel considérable de gaz de houille.

Although shale gas systems constitute a new target for commercial hydrocarbon production, only a little attention has been paid to the evolution of these unconventional systems with increasing thermal maturation. This study reports the characterization of samples of the Lower Toarcian (Lower Jurassic) Posidonia Shale from northern Germany at varying levels of thermal maturity. Observations were made using an original combination of focused ion beam-scanning electron microscopy (FIB-SEM) and transmission electron microscopy (TEM). The paper documents the formation of microfracture-filling bitumen in close assotiation with kerogen residues with increasing maturity. Porosity evolves from mostly submicrometric interparticle pores in immature samples to intramineral and intraorganic pores in overmature (gas mature) samples. This intraorganic nanoporosity has most likely come about by the exsolution of gaseous hydrocarbon and been hydrocarbon wet during the thermal maturation processes. Although FIB-SEM and TEM images are small compared to field size, this study emphasizes the need for nanoscale imaging to better constrain hydrocarbon generation processes in gas shale systems.

Methane-rich gas occurs in the total organic carbon–rich Alum Shale (Furongian to Lower Ordovician) in southern Sweden. The lower part of the thermally immature Alum Shale was impregnated by bitumen locally generated by heating from magmatic intrusions from the Carboniferous to the Permian. Organic geochemical data indicate that the migrated bitumen is slightly degraded. In the upper Alum Shale, where methane is the main hydrocarbon in thermovaporization experiments, centimeter-size calcite crystals occur that contain fluid inclusions filled with oil, gas, or water. The Alum Shale is thus considered a mixed shale oil–biogenic shale gas play. The presented working hypothesis to explain the biogenic methane occurrence considers that water-soluble bitumen components of the Alum Shale were converted to methane. A hydrogeochemical modeling approach allows the quantitative retracing of inorganic reactions triggered by oil degradation. The modeling results reproduce the present-day gas and mineralogical composition. The conceptual model applied to explain the methane occurrence in the Alum Shale in southern Sweden resembles the formation of biogenic methane in the Antrim Shale (Michigan Basin, United States). In both models, melting water after the Pleistocene glaciation and modern meteoric water may have diluted the contents of total dissolved solids (TDS) in basinal brines. Such pore waters with low TDS contents create a subsurface aqueous environment favorable for microbes that have the potential to form biogenic methane. Today, biogenic methane production rates, with shale as the substrate using different hydrocarbon-degrading microbial enrichment cultures in incubation experiments, range from 10 to 620 nmol per gram and per day.

A novel hydrogeochemical modeling approach is developed to unravel thermochemical sulfate reduction (TSR) in hydrocarbon reservoirs. Our numerical model couples a web of interconnected hydrogeochemical reactions to three-dimensional (3-D) and reservoir-wide diffusive mass transport. Our modeling approach simulates a semigeneric gas reservoir sealed by anhydrite. The calculated diagenetic processes fit the observations in reservoirs affected by TSR: formation of water, precipitation of calcite, metal (di-)sulfides, and elemental sulfur as replacements of dissolved anhydrite at the expense of CH4(g), as well as formation of hydrogen sulfide (H2S). By varying input parameters, the crucial factors controlling TSR have been identified. Our results highlight that reservoir-wide diffusive mass transport is one prerequisite for TSR. An increase in the rate constant of abiotic sulfate reduction (ASR) and in diffusive mass fluxes, as well as lack of precursor minerals for metal (di-)sulfide precipitation, can increase the souring intensity and accelerate H2S outgassing. In contrast, precipitation of elemental sulfur, which is stable according to the chemical thermodynamics, weakens H2S formation. Our modeling shows that TSR is complex and cannot be represented by the single reaction ASR and by simple correlations between the rate constant of ASR and the H2S gas content. The application of 3-D reactive transport modeling presented here, despite its semigeneric nature, provides a good example of how such an approach can be used ahead of drilling. Our modeling helps to investigate TSR in time and space to quantify the mass conversion of all reactants involved within this web and to predict the souring level.

Shale gas is produced from fine-grained siliciclastic sediments that are typically rich in organic carbon. Nearly all shales contain thermal gas generated in situ at mature to overmature levels of thermal alteration, although gas of biogenic origin is also produced from some shales. While shale gas production in the USA began in 1821, it is only in the last few years that it has become widely significant (currently about 8% of the domestic gas). In contrast, European shale gas exploration is still in its infancy. In general, European sedimentary basins offer the best potential for shale gas occurrence because thick, organic matter-rich sediments occur in nearly all Phanerozoic strata. Even so, there is little knowledge about the factors controlling shale gas generation and, more importantly, shale gas production in European basins. These factors are not necessarily the same as those that control commercial shale gas production in the USA. Palaeozoic sediments of Cambrian to Ordovician age are currently being tested for their shale gas potential and productivity in Sweden, as are those of Silurian age in Poland. Moreover, Lower and Upper Carboniferous sedimentary successions from England in the west to Poland in the east probably contain shale gas, but their depth, thickness and thermal maturity may be limiting factors for exploration in continental regions. Lower Carboniferous black shales in the Dniepr–Donets Basin of the Ukraine may also hold a significant potential. Moreover, organic-rich sediments of Oligocene/Miocene age in the Paratethyan Basin may offer shale gas potential, for example in the Pannonian Basin. At present, Upper Jurassic black shales are currently being tested for their shale gas potential in the Vienna Basin. European analogues of known biogenic shale gas systems may occur locally in organic-rich Lower Cretaceous sediments in the North German Basin with gas generation being related to Pleistocene glaciation/deglaciation cycles.