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Rundle oil shale containing 12.9 wt.% of organic carbon was retorted using a combustion-type retort. It was possible to quantify the reduction in oil yield (compared with Fischer assay) due to the combustion of oil vapour during retorting. The oil yield was only 7.2 wt.%, compared with a Fischer assay oil yield of 8.7 wt.%, when retorting was carried out with excess air but no additional source of carbon. Oil yields could be improved by mixing lignite, available from within the Rundle deposit, with oil shale before retorting. Oil yields, based on charge, from mixtures containing more than 10% lignite decreased with increasing lignite content, but were virtually identical with Fischer assay oil yields from the mixtures. The maximum oil yield was about 8.5 wt.% for 6 wt.% lignite in the mixtures. The resulting oils were slightly heavier and more aromatic than the oils obtained by Fischer assay, but showed no significant difference in oxygen content.

Oil shale and lignite from the Rundle/Stuart deposit and a range of mixtures of the two, have been pyrolysed in a Fischer retort. Oil yields decreased linearly from 8.67 to 5.19 wt% as the lignite content increased from 0 to 100%. Yields of gas, water and spent shale also varied linearly. H C atomic ratios of the resulting oils varied from 1.70 to 1.47 and, when plotted against oil shale percentage, a slightly concave curve resulted. Similarly, carbon aromaticity determined by n.m.r. varied from 0.33 to 0.48 and resulted in a slightly convex curve when graphed against oil shale content. It appears that oil produced by blending shale and lignite is more aromatic than expected for non-interacting components. Results show that oil from an intimate geological mixture is more aromatic than that from a comparable synthetic mixture.

Shale oil recovered from Fischer assays of fresh and artificially weathered oil shales have been compared using 1 H and 13 C nuclear magnetic resonance spectroscopy and elemental analyses. Rundle, Julia Creek and Green River shales were exposed to air at 100 °C for 60 weeks to simulate either geological weathering, or oxidation during drying or stockpiling prior to retorting. As a result of oxidation, the oils became more aromatic, with higher oxygen contents and shorter average aliphatic chain lengths. Variations in the distribution of phenols, acids and ketones, as well as heterocyclic compounds containing nitrogen and sulphur, have been detected.

An attempt has been made over 60 weeks to simulate experimentally the weathering of Rundle, Julia Creek and Green River oil shales. Finely-ground shales were subjected to three types of ‘weathering’: 1. (1) 22 °C in air without water or sunlight (‘internal’ conditions) 2. (2) 10–35 °C under water with sunlight (‘external’ conditions) 3. (3) 100 °C in air without water or sunlight (‘extreme’ conditions). All shales exhibited decreases in oil yields by Fischer assay, the highest loss being 90 wt % for Julia Creek shale under extreme conditions for 60 weeks. Solid-state 13C n.m.r. spectra of kerogens before and after weathering under extreme conditions for 60 weeks confirm increased aromaticity and greater concentrations of oxygenated functional groups. Elemental analyses show that, for these kerogens, H/C ratios decreased by ≈ 30% and O/C ratios increased by ≈ 300%. The results are important when considering natural geological weathering of shale seams, oxidation of stockpiled shale and prolonged drying of shale at elevated temperatures.

Vanadyl porphyrins have been detected in a series of oil shale and weathered coquinite samples from the Toolebuc Formation, Queensland, Australia. Concentrations of soluble vanadyl porphyrins range from < 1 to 730 μg g−1. Organically bound vanadium has also been found in kerogens isolated from oil-shale samples taken at locations up to several hundred kilometres apart. Variations in the concentration of both vanadyl porphyrins and kerogen-bound V are probably due to recent weathering. By preferentially removing smaller aliphatic molecules, weathering progressively renders the remaining kerogen more aromatic and ultimately solubilizes all organic matter in the shales. At the same time, organically bound V is released and becomes associated with the inorganic fraction of the weathered shale.

Differing degrees of oxidation, caused by weathering at the surface, are evident in the Julia Creek oil shale deposit. Weathering results in decreased oil yields and its extent is indicated by the oil/organic carbon ratio. In a series of carefully selected samples, this ratio (by weight) varies from 0.55 for ‘fresh’ shale to 0.38 for appreciably altered shale. Oxidation of kerogen is reflected in the elemental composition of kerogens obtained by demineralization of the samples. FT-i.r. spectra of kerogens show that CH concentrations decrease and COOH contents increase with in situ oxidation. Nuclear magnetic resonance spectroscopy gives clear evidence that, as well as oil quantity, oil quality progressively changes with shale weathering. Results are, in general, directly comparable with those for artificially weathered shales.

The hydrocarbon secreting alga Botryococcus has been identified in organic remains of sediments ranging from Precambrian to Recent, and is believed to have been a major source material for petroleum generation throughout the geological time. In some petroleum source rocks of Lower Palaeozoic and Precambrian age, identification of the alga is only possible by electron microscopy. Transmission electron microscopy (TEM) has been used in the present study to identify microstructures of the algal remains in a range of oil shales and petroleum source rocks. It has been established that Botryococcus is the predominant alga in the Kukersite oil shale of Estonia. Similarly, the alga has been shown to be a major contributor to petroleum source rocks in Cambrian and Precambrian sedimentary basins in Australia. TEM has been applied to observations of Botryococcus in torbanites and to products from simulated maturation experiments on torbanite. A comparison with algal remains from Cambrian and Precambrian sediments ranging from undermature to overmature, enabled the distinction of organic matter in various stages of oil generation. Maturation/thermal effects on alginite have been established by reflectance and fluorescence, and compared with experimental results.

Elemental analyses, X-ray diffraction, thermal and isotopic analyses, gas chromatography-mass spectrometry, electron spin resonance, nuclear magnetic resonance spectroscopy and demineralizing techniques have been used to evaluate the effect of a small igneous intrusion on Rundle oil shale. Each set of results contributes to an overall appreciation of how in situ pyrolysis of a highly aliphatic kerogen occurs. As in previous studies, application of a range of methods gives a better understanding than any of the techniques on its own. Significant conclusions are as follows: (1) the shale samples closest to the intrusion contain the least organic matter; (2) a “micro-reservoir” for expelled volatiles was identified ∼ 1 m below the intrusion; (3) the hydrogen-deficient carbonaceous residue remaining close to the intrusion produces no oil on further heating; and (4) the major effect of the intrusive event was the in situ pyrolysis of the oil shale, the severity of alteration decreasing with distance from the contact.

The amount of oil that can be generated from a kerogen under natural conditions is an important parameter in source rock assessment. Similarly, the quantity of oil able to be formed from a coal or kerogen during much more rapid pyrolysis is a crucial factor in oil shale and coal conversion studies. An approximate relation based on atomic ratios is derived for slow geological heating but is also valuable for comparing samples under other conditions. The percentage of oil, on a weight basis, that can be generated is given by: Oil = 66.7 H C − 57.0 O C −33.3 . Typical results for twelve Australian coals and twelve world oil shales are given as examples.