Condor Oil Shale Research Articles

Chemical characterization of shale oil from Condor, Australia

Fischer assay shale oil from the Condor oil shale deposit at Proserpine, Queensland, was chemically separated into 20 fractions and analysed by gas chromatography-mass spectrometry. Over 600 compounds were identified, including homologous series of linear alkanes, 2-methylalkanes, alkylcyclopentanes, alkylcyclohexanes, 1-, 2-, 3- and 4-alkanes, alkylcyclohexenes, alkylcyclopentenes, linear dienes, alkylbenzenes, alkylindans, alkylnaphthalenes, nitriles, 2- and 3-alkanones. Substituted cyclopentanes, cyclohexanes, benzenes, naphthalenes, polycyclic aromatic hydrocarbons, phenols, pyridines, dihyroindoles, quinolines and tetrahydroquinolines were also identified. The Condor oil is highly aliphatic in character (H/C=1.7), with alkanes (≈28%) alkenes (≈18%) alkadienes (≈2%) nitriles (≈11%) and alkanones (≈4%) being the most abundant components. The carbon chain length distributions of the alkanes, nitriles and methyl ketones (bi-, tri- and bimodal respectively) are indicative of both algal and higher plant sources with algal predominating.

THE GEOLOGY OF THE CONDOR OIL SHALE DEPOSIT—ONSHORE HILLSBOROUGH BASIN

The Condor oil shale deposit lies in sediments of the Tertiary Hillsborough Basin, on the north-central Queensland coast. The basin is an elongate, southeast-trending graben, most of which lies under Repulse Bay and the Hillsborough Channel. Palaeozoic volcanics and sediments and Palaeozoic- Mesozoic intrusives form the basement. Current drilling has been conducted onshore and is concentrated on the south-western flank of the basin. Beneath a veneer of Quaternary alluvial sand and clay, averaging 20 m thick, the drilling has differentiated six informal stratigraphic units in the Tertiary sequence. The 'sandstone unit', which is at the base of the sequence and is at least 140 m thick, consists of fine to very coarse sandstone and may be coarsening towards the southeast. The overlying 'carbonaceous unit' (10-50 m) comprises sandstone, coal and carbonaceous shale, and loses its identity in the southeast.Abruptly overlying these two units is a sequence of entirely different character. The 'brownish black' and the 'brown oil shale units', totalling about 400 m, comprise massive lamosite. The 'transitional unit (80-180 ) consists of thin graded sandstone beds with laminated oil shale and siltstone. The 'upper unit', at least 500 m thick is similar, but contains a higher proportion of sandstone in thicker beds.Bedding dips regularly at 14°-16° to the northeast, disrupted in part by a parallel series of normal, west-dipping, strike faults, which die out towards the southeast. Towards the north of the project area these faults appear to be offset by a major east-west structure, probably a syndepositional fault. A wedge of sandstone appears within the 'brown oil shale unit' immediately north of the structure's inferred position. The 'sandstone' and 'carbonaceous units' were probably deposited in fluvial and swampy-deltaic environments respectively. The oil shale was deposited in a shallow, saline and euxinic lake or bay, while the sandstone intercalations of the upper two units, derived from the north and northeast, indicate later regression of the lake or bay.The lower part of the 'brown oil shale' and upper part of the 'brownish black' units aggregate about 200 m and constitute the main zone of interest. This zone has an average grade of 63.5 litres oil/tonne of shale oil at zero per cent moisture (LTOM). Using a cut-off grade of 40 LTOM the resources has been calculated at 6.25 billion barrels of in situ shale oil.