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ABSTRACT: The oil shale exploration program in Jordan is undertaking great activity in the domain of applied geophysical methods to evaluate bitumen‐bearing rock. In the study area, the bituminous marl or oil shale exhibits a rock type dominated by lithofacies layers composed of chalky limestone, marls, clayey marls, and phosphatic marls. The study aims to present enhancements for oil shale seam detection using progressive interpretation from a one‐dimensional inversion to a three‐dimensional modelling and inversion of ground‐based transient electromagnetic data at an area of stressed geological layers. The geophysical survey combined 58 transient electromagnetic sites to produce geoelectrical structures at different depth slices, and cross sections were used to characterise the horizon of the most likely sites for mining oil shale. The results show valuable information on the thickness of the oil shale seam at 3.7 Ωm, which is correlated to the geoelectrical layer between 2‐ and 4 ms transient time delays, and at depths ranging between 85 and 105 m. The 300 m penetrated depth of the transient electromagnetic soundings allows the resolution of the main geological units at narrow resistivity contrast and the distinction of the main geological structures that constrain the detection of the oil shale seam. This geoelectrical layer at different depth slices illustrates a localised oil shale setting and can be spatially correlated with an area bounded by fold and fault systems. Also, three‐dimensional modelling and inversion for synthetic and experimental data are introduced at the faulted area. The results show the limitations of oil shale imaging at a depth exceeding 130 m, which depends on the near‐surface resistivity layer, the low resistivity contrast of the main lithological units, and the degree of geological detail achieved at a suitable model's misfit value. [ABSTRACT FROM AUTHOR]

High-pressure methane sorption isotherms were measured on seven representative samples of Silurian shales from the Barrandian Basin, Czech Republic. Excess sorption measurements were performed at a temperature of 45 °C and at pressures up to 15 MPa on dry samples, using a manometric method. Experimental methane high-pressure isotherms were fitted to a modified Langmuir equation. The maximum measured excess sorption parameter ( n max ) and the Langmuir sorption capacity parameter ( n L ) were used to study the effect of TOC content, organic maturity, inorganic components and pore size distribution on the methane sorption capacity. The values of n max ranged from 0.050 to 0.088 mmol.g −1 , and the values of n L ranged from 0.068 to 0.133 mmol.g −1 . The studied shale samples with random reflectance R r of graptolite 0.56–1.76% had a very low TOC content from 0.34 to 2.37 wt% and dominant mineral fractions. Illite was the prevailing clay mineral (0–51%). Organic matter of the Silurian black shales was consisted of residues of graptolites, chitinozoans, two types of bitumen including dispersed and massive bitumens, recycled organic matter, and organic detritus. In the shales, the occurrence of fractures parallel with the original sedimentary bending was highly significant. A greater proportion of fragments of carbonaceous particles of graptolites and bitumens in the Barrandian shales had a smooth surface without pores. The sample porosity Por calc ranged from 4.6 to 18.8%. In most samples, the micropore volumes were markedly lower than the meso- and macropore volumes. No relation has been proven between TOC-normalized excess sorption capacities or the TOC-normalized Langmuir sorption capacities and thermal maturation of the shales. The methane sorption capacities of shale samples show a positive correlation with TOC and a positive correlation with the clay content. The assumption that the sorption capacity is a function mainly of the microporous system of shales was not confirmed. The highest sorption capacity was observed in shale samples with the lowest volume of micropores and the highest TOC content, indicating that the organic matter content and the microporosity of clay minerals are the principal factors affecting the sorption capacity of shale samples. [ABSTRACT FROM AUTHOR]

Organic-rich deposits of Qalikuh locality, Zagros Basin, Southwest of Iran are unconventional hydrocarbon resources considered as an oil shale, which is hosted within a carbonate succession with the age range of Middle Jurassic to Lower Cretaceous. Leco carbon, Rock–Eval VI and modified Fischer Assay analysis were performed on some outcrop samples of these resources to investigate the occurrence of oil shale. In the studied samples, mean total organic carbon (TOC) is 17.3 wt.% and the average of petroleum genetic potential (S 1 + S 2 ) is 98 kg HC/t rock. Furthermore, TOC has direct relationship with petroleum genetic potential. Hydrogen index (HI)–T max diagram indicates that the organic matter corresponds to Type II kerogen of probable marine origin with high quality of oil generation. According to Rock–Eval data, and bitumen reflectance (BR r ), the samples are thermally early mature. Based on the studied samples, oil yield of the Qalikuh oil shales ranges from 6.1 to 7.9 wt.%. Mean oil–gas ratio is 2.7 and mean oil yield is 56.7 l/t rock. According to the observations, the production value of Qalikuh oil shale is more or less similar in the entire studied regions. Whereas the total production is below the expected values, the produced oil is considerably lighter (higher API) than that of most other known oil shales. [ABSTRACT FROM AUTHOR]

The uptick in hydrocarbon production from shale in the United States has generated interest in metrics of unconventional reservoir quality, like permeability. We use conventional gas sorption to characterize shale microstructure, which provides insight on the features that govern mass transport. The gas sorption data are analyzed to determine the surface area, AS (m²/g), and pore volume, VP (cm³/g) of 30 samples from basins across North America. With this information, we quantify the effect of composition and thermal maturity on shale microstructure. In particular, we find that the specific surface area of the organic component evolves from ~50 m²/g total organic carbon (TOC) in immature shale to ~500 m²/g TOC for regions that produce dry gas. The increase in AS is accompanied by an increase in VP and concomitant decline in average pore size (e.g., rH = 4VP/AS). We contend that the latter is due to the development of nanometer-sized pores in kerogen as it is converted to mobile hydrocarbon which is ultimately expelled. This hypothesis is supported by similar measurements on companion samples after bitumen extraction or combustion, which underscore the intimate spatial association of petroleum and kerogen. Coupled with information on accessibility to the porosity garnered by varying the particle size, these results establish a clear link between organic matter, thermal maturity, and reservoir quality in unconventional shale systems. [ABSTRACT FROM AUTHOR]