@article{doi1013065d25c0cd16c111d78645000102c1865d, author = "Weeks, Lewis G. and Hopkins, Brian M.", title = "Geology and Exploration of Three Bass Strait Basins, Australia", year = "1967", journal = "AAPG Bulletin", abstract = "ABSTRACT Three major Mesozoic-Tertiary basins adjoin in east-west alignment along the eastern third of the south coast of Australia, for a distance of about 700 miles. The total area embraced by the three basins is about 100, 000 square miles, and it includes part of three of Australia’s six states. Three-fourths of the area is offshore shelf. The general east-west alignment of the basins resulted from sharp taphrogenic breakdown across the generally north-south Paleozoic orogenic trend of eastern Australia and Tasmania. The main faults and many of the basin features tend to have northeasterly or northwesterly trends, suggesting that rotational or transcurrent stresses were involved in the breakup and subsidence. Sedimentation began at least as early as the Late Jurassic. The Mesozoic is an estuarine to marine, poor- to well-sorted terrigenous clastic series. The Tertiary is largely marine and is more uniformly developed throughout. The lower third of the Tertiary contains extensive, generally highly porous and permeable coastal sandstone beds together with some shale and varying amounts of coal and carbonaceous beds. The middle beds consist mainly of shale. The upper third or more has a considerable amount of limestone and marl. Several unconformities are recognized. Though not all sediments bear marine fossils, the contained waters are saline beyond the limits of the rather extensive fresh-water flushing onshore. The Gippsland or eastern basin includes approximately 20, 000 square miles. At least 10, 000 feet of rapidly deposited Upper Jurassic-Cretaceous terrigenous clastics fills a down-faulted central trough and overlaps the basin shelves on the north and south; and about 9, 000 feet of more widely extending Tertiary sandstone, shale, marl, and limestone comprises the remainder of the basin fill. The deeply silled Bass basin separates the island State of Tasmania from the mainland. It occupies an area of 35, 000 square miles. The section consists of 12, 000 feet or more of sandstone, shale, marl, and limestone, together with some coal, of Eocene and earlier ages. Deposition began in the central part of the basin, probably at least as early as Late Cretaceous time, and it continued throughout the Tertiary. The deposition progressively overlapped toward all flanks. The western, or Otway, basin includes an area of about 45, 000 square miles. In this basin, the Mesozoic consists of sandstone, shale, siltstone, and mudstone. Deposition began during the latter part of Jurassic time and it continued, except for recognizable intervals of non-deposition, into the Paleocene. The maximum thickness exceeds 15, 000 feet. A maximum of about 8, 000 feet of overlapping Tertiary sandstone, shale, marl, and limestone completes the basin fill. Potential petroleum traps of the following types occur: tectonic folds; fault or fault-block structures; massive, elongate sandstone bodies associated with pronounced transgressive overlap, shale interfingering, and compaction drape; porosity abutment both above and below extensive low-angle unconformities; unconformable overlap by basin-sink sediments across broad-bottom highs and against and over major fault scarps; structural noses; extensive progressive flank overlap around a deeply silled basin by a sandstone, shale, marl, and limestone section; and porosity pinchouts. Since the mid-1920s, 130 exploratory borings have been drilled onshore in the extensively freshwater-flushed basin flanks. Numerous non-commercial oil and gas shows were logged. In 1965 and 1966, five exploratory wells were drilled offshore, up to the April, 1966, date of this paper. Three of these were located on well-defined closure in the Gippsland basin and resulted in major wet gas and oil discoveries in Eocene and Upper Cretaceous sandstone reservoirs. Prior to farmout of each of the three basins, successively from east to west, 18, 000 miles of aerial magnetic and 5, 320 miles of conventional seismic surveys were carried out under the direction and assistance of the writers. Comprehensive basin studies and compilations completed the preliminary investigations. Not included in the foregoing are various geophysical surveys on a much smaller scale by other companies and government agencies. Also not included are many hundreds of miles of additional shooting by the farmee preparatory to drilling.", url = "https://doi.org/10.1306/5d25c0cd-16c1-11d7-8645000102c1865d", doi = "10.1306/5d25c0cd-16c1-11d7-8645000102c1865d", openalex = "W1997201393" } @article{doi101071aj70012, author = "James, E. A. and Evans, P. R.", title = "THE STRATIGRAPHY OF THE OFFSHORE GIPPSLAND BASIN", year = "1971", journal = "The APPEA Journal", abstract = "The Gippsland Basin in south-eastern Australia mainly underlies the continental shelf between eastern Victoria and Tasmania. It is filled with Lower Cretaceous-Recent sediment and has become a major source of hydrocarbons for the Australian market. Forty-two wildcat and stepout wells, additional development wells and over 7,000 miles of seismic lines provide a framework on which to build the region\'s geological history. The time-stratigraphy of the basin is derived from extensive use of spore-pollen assemblages in the mainly non-marine Cretaceous-Eocene and foraminifera in the marine Oligocene-Pliocene, largely complemented by seismic and to a lesser extent electric log correlations. Ten Cretaceous and five Paleocene-Eocene spore-pollen zones and fourteen Oligocene-Pliocene foraminiferal zonules are recognized. Only broad-scale lithostratigraphic units, initially recognized along the northern, onshore margin of the basin are traceable offshore. The Lower Cretaceous is represented by at least 10,000 feet of non-marine greywacke of the Strzelecki Group. The Upper Cretaceous-Eocene, with a cumulative thickness of 15,000 feet is termed the Latrobe Group and consists mainly of lacustrine and fluviatile elastics. Channels dissected the top of the Latrobe Group during the Eocene and were filled with sediments recognizable as distinct sequences within the group and termed the Flounder and Turrum Formations. A destructive marine phase during latest Eocene time left the glauconitic Gurnard Formation as the youngest member of the Group. Subsequent marine inundation of the basin resulted in deposition of up to 1,500 feet of calcareous mudstone referred to the Lakes Entrance Formation and up to 5,000 feet of marl, calcarenite and limestone of the Gippsland Limestone during the Oligocene and Miocene. Up to 1,000 feet of Pliocene- Recent calcarenite, micrite and marl complete the sedimentary sequence.", url = "https://doi.org/10.1071/aj70012", doi = "10.1071/aj70012", openalex = "W2746622122" } @article{doi101306819a3e2e16c511d78645000102c1865d, author = "Tissot, B. and Califet-Debyser, Y. and Deroo, G. and Oudin, J.L.", title = "Origin and Evolution of Hydrocarbons in Early Toarcian Shales, Paris Basin, France", year = "1971", journal = "AAPG Bulletin", abstract = "ABSTRACT The purpose of the study was to investigate the conditions of formation and evolution of hydrocarbons during burial and related diagenesis of sediments. Early Toarcian shales (Early Jurassic), in the Paris basin, were selected because all parameters except temperature and pressure (both related to burial of sediments) remain constant—age, nature of fossil organisms and clay minerals, and conditions of deposition (which were fairly homogeneous in the formation across the surveyed area). The amounts of the different organic constituents and some structural properties of the molecules reveal an orderly variation, depending on maximum depth of burial. At the beginning of burial, the transformation ratio of organic matter to hydrocarbons is low and changes little to a depth of 1,500 m, where the ratio increases markedly with increased depth. A detailed study shows that hydrocarbons present at shallow depth are directly inherited from original living matter or result from early transformation in sediment, without changing the general structure of the molecule (like molecules of steroid and triterpenoid types). When burial becomes sufficiently deep, these characteristic structures are diluted among newly formed hydrocarbons generated by thermal degradation of organic matter. Interpretation of the observations leads to the conclusion that burial (i.e., increase of pressure and especially of temperature) constitutes the determining factor in the evolution of organic matter. The temperature rise promotes the formation of petroleum compounds, particularly hydrocarbons, at the expense of kerogen. A general reaction scheme is proposed, based on hypothesis on the structure of kerogen, and on the observed relations of the various organic compounds.", url = "https://doi.org/10.1306/819a3e2e-16c5-11d7-8645000102c1865d", doi = "10.1306/819a3e2e-16c5-11d7-8645000102c1865d", openalex = "W2108200189" } @article{hocking1972geologic, author = "Hocking, J. Barry", title = "GEOLOGIC EVOLUTION AND HYDROCARBON HABITAT GIPPSLAND BASIN", year = "1972", journal = "The APEA Journal", abstract = "The Gippsland Basin of southeastern Australia is a post-orogenic, continental margin type of basin of Upper Cretaceous-Cainozoic age. Gippsland Basin evolution can be traced back to the establishment of the Strzelecki Basin, or ancestral Gippsland Basin, during the Jurassic. Gippsland Basin sedimentation commenced in the middle to late Cretaceous and is represented as a gross transgressive-regressive cycle consisting of the continental Latrobe Valley Group (Upper Cretaceous to Eocene or Miocene), the marine Seaspray Group (Oligocene to Pliocene or Recent), and finally the continental Sale Group (Pliocene to Recent). The hydrocarbons of the Gippsland Shelf petroleum province were generated within the Latrobe Valley Group and are trapped in porous fluvio-deltaic sandstones of the Latrobe. At Lakes Entrance, however, oil and gas are present in a marginal sandy facies of the Lakes Entrance Formation (Seaspray Group). The buried Strzelecki Basin has played a fundamental role in the development and distribution of the Cainozoic fold belt in the northern Gippsland Basin. The Gippsland Shelf hydrocarbon accumulations fall within this belt and are primarily structural traps. The apparent lack of structural accumulations onshore in Gippsland is largely due to a Plio-Pleistocene episode of cratonic uplift that was accompanied by basinward tilting of structures and meteoric water influx. The non-commercial Lakes Entrance field, located on the stable northern flank of the basin, is a stratigraphic trap and may serve as a guide for future exploration.", url = "https://doi.org/10.1071/aj71022", doi = "10.1071/aj71022", number = "1", openalex = "W2748450619", pages = "132-137", volume = "12" } @article{doi101071aj72011, author = "Shibaoka, Michio and Bennett, Alan J. and Gould, Kathleen", title = "DIAGENESIS OF ORGANIC MATTER AND OCCURRENCE OF HYDROCARBONS IN SOME AUSTRALIAN SEDIMENTARY BASINS", year = "1973", journal = "The APEA Journal", abstract = "It is important that petroleum exploration geologists know the critical depth limits where oil is generated from original organic matter in sediments and where the oil changes to natural gas. Organic matter is very sensitive to temperature. The maximum temperature experienced is related to its depth of burial. CSIRO has used the composition and physical properties of various types of organic matter in shaly rocks as indicators for the degree of diagenesis caused by this heat alteration. The reflectance of vitrinite in associated coals is used as the primary standard, and carbon content of such coals as the secondary parameter to distinguish various stages of oil and gas generation. Depth-reflectance curves are useful 1., for estimating palaeogeothermal gradients, 2., for determining the degree of diagenesis at a particular depth and also 3., for estimating the approximate thickness of sediments subsequently lost after deposition. The petroleum potential of some Australian sedimentary basins is reviewed in the light of this knowledge. In the Northwest Shelf area and in the Capricorn and Otway Basins, the oil generation zone is deeper than in the Cooper, Galilee and Surat Basins. In the Bowen and Sydney Basins and several other small basins along the eastern coast of Australia, this zone is very shallow, and in some areas the oil generation zone has been completely lost by erosion. The areas most promising for oil fields are those where little erosion of sediments has taken place subsequent to deposition and diagenesis, provided that all other geologic factors for hydrocarbon accumulation are present.", url = "https://doi.org/10.1071/aj72011", doi = "10.1071/aj72011", openalex = "W2748659034" } @article{shibaoka1978hydrocarbon, author = "Shibaoka, M. and Saxby, J. D. and Taylor, G. H.", title = "Hydrocarbon Generation in Gippsland Basin, Australia—Comparison with Cooper Basin, Australia", year = "1978", journal = "AAPG Bulletin", abstract = "The Gippsland basin, with its oil and gas resources, provides an excellent area for organic geochemical and petrologic research on the generation, migration, and alteration of hydrocarbons. The main source rocks for the known oil and gas deposits appear to be at depths greater than those reached by any of the exploration wells. The type of organic material originally present in the rocks now at depths greater than 4,000 m (and now at temperatures greater than 130°C) is unknown but, at least within the Latrobe Group, it appears to have had a high exinite content similar to that observed in the upper part of the group. At such temperatures, thermal cracking of exinite would yield a considerable amount of oil, whereas the products from vitrinite would be mainly gas and solid residue. Migration to reservoirs below the unconformity at the top of the Latrobe Group would follow. Both generation and migration are believed to be occurring at the present time, as immature carbonaceous material is being exposed to higher temperatures by deeper burial. Chromatographic analysis of Gippsland crude oils suggests that the oils originate from solid organic matter derived from algae and land plants, the latter contributing to the high wax content. Gas generation in the Cooper basin provides an interesting comparison with the Gippsland basin in relation to type of organic material and geothermal history.", url = "https://doi.org/10.1306/c1ea4fc7-16c9-11d7-8645000102c1865d", doi = "10.1306/c1ea4fc7-16c9-11d7-8645000102c1865d", number = "7", openalex = "W2120810739", pages = "1151-1158", volume = "62", references = "doi1010160016703769900404, doi1010160016703776900326, doi101071aj69007, doi101071aj70012, doi101071aj72011, doi10130683d91f5116c711d78645000102c1865d" } @techreport{shibaoka1978hydrocarbon1, author = "Shibaoka, M. and Saxby, J. D. and Taylor, G. H", title = "Hydrocarbon generation in Gippsland basin, Australia--Comparison with Cooper Basin, Australia", year = "1978", howpublished = "Bulletin of the American Association of Petroleum Geologists, v. 62, no. 7, p. 1151-1158", note = "talkorigins\_source = {true}; raw\_reference = {Shibaoka, M., Saxby, J. D., and Taylor, G. H., 1978, Hydrocarbon generation in Gippsland basin, Australia--Comparison with Cooper Basin, Australia: Bulletin of the American Association of Petroleum Geologists, v. 62, no. 7, p. 1151-1158.}" } @article{doi101071eg979149, author = "Middleton, M. F.", title = "Heat flow in the Moomba, Big lake and Toolachee gas fields of the Cooper Basin and implications for hydrocarbon maturation", year = "1979", journal = "Exploration Geophysics", abstract = "Heat flow in the Moomba, Big Lake and Toolachee gas fields of the Cooper Basin is estimated from corrected bottom hole temperatures and an assumed bulk thermal conductivity of 5 × 10–3 cal/cm sec °C. The Moomba and Big Lake fields have heat flows of 2.61 and 2.60 microcal/cm2 sec C. Samples of basement granite from the Moomba and Big Lake fields yield heat production of 17.5 × 10–13 and 24.2 × 10–13 cal/cm3sec, respectively, which are sufficient to account for observed surface heat flow if the granite layer is between 7 to 10 km thick. Hydrocarbon maturation and coal rank (expressed as vitrinite reflectance) in the high heat flow Moomba-Big Lake region exhibits a different correlation to maximum palaeo-temperature and depth than in lower heat flow regimes. The degree of maturation may be dependent on the thermal energy available for metamorphism (i.e. heat flux), rather than the temperature of the basin.", url = "https://doi.org/10.1071/eg979149", doi = "10.1071/eg979149", openalex = "W2055036038", references = "doi101071aj72011" } @article{doi10130603b5a31316d111d78645000102c1865d, author = "Snowdon, L R and Powell, T. G.", title = "Immature Oil and Condensate—Modification of Hydrocarbon Generation Model for Terrestrial Organic Matter", year = "1982", journal = "AAPG Bulletin", abstract = "ABSTRACT Petroleum has been found in Canadian frontier basins in reservoirs which have undergone low levels of thermal alteration (vitrinite reflectance ≤ 0.6\%Ro). Paraffin indices, stable carbon and hydrogen isotope contents, pristane to nC17 ratios, and diterpenoid biologic markers have been used to assess the level of maturity of the hydrocarbons in the reservoir independently of the level of maturity of the reservoir itself and of the surrounding shale units. In the Tertiary of the Beaufort-Mackenzie basin, naphthenic oils and condensates have been generated from terrestrially derived organic matter in source rocks juxtaposed with the reservoir at reflectance levels of 0.4 to 0.6\%R0. However, condensates discovered in reservoirs which are thermally immature on the Labrador Shelf have undergone extensive vertical migration and can be classed as conventional mature to overmature condensates. Hydrocarbons discovered in the Lower Cretaceous of the Beaufort-Mackenzie basin and also those of the Scotian Shelf are more or less in place in that they are at a level of thermal alteration about equivalent to that of the reservoirs in which they are trapped. The source for the early oils and condensates is considered to be resinite occurring dispersed in coal fragments. The proportion of resinite, liptinite, and vitrinite in the organic matter of terrestrial source rocks strongly controls both the level of thermal alteration necessary for the section to function as an effective source rock and the ultimate product (gas, oil, or condensate) which will be generated.", url = "https://doi.org/10.1306/03b5a313-16d1-11d7-8645000102c1865d", doi = "10.1306/03b5a313-16d1-11d7-8645000102c1865d", openalex = "W2149556370", references = "doi101071aj72011" } @article{doi10130603b5b72216d111d78645000102c1865d, author = "James, A. T.", title = "Correlation of Natural Gas by Use of Carbon Isotopic Distribution Between Hydrocarbon Components", year = "1983", journal = "AAPG Bulletin", abstract = "ABSTRACT The natural distribution of carbon isotopes between hydrocarbon gas components is used for (1) determining a gas’s maturity, (2) correlating a reservoired gas to its source, (3) correlating one reservoired gas with another, and (4) recognizing gas mixtures. Calculated separations of carbon isotopes between the normal alkane components of a natural gas have been related to source rock maturity by use of a single, continuous diagram, independent of source type. Actual data from a wide variety of geologic settings and geologic ages confirm this relationship and demonstrate its applicability to the source rock Levels of Organic Metamorphism ranging from 8 to 13, covering the entire range of oil and wet-gas generation. At greater maturities, the wet-gas components are found to undergo thermal degradation, losing their usefulness for correlation. Three examples showing indigenous gas (west Texas), non-indigenous gas (Gippsland basin, Australia), and gas mixtures from multiple sources (southeastern Alberta) illustrate exploration applications.", url = "https://doi.org/10.1306/03b5b722-16d1-11d7-8645000102c1865d", doi = "10.1306/03b5b722-16d1-11d7-8645000102c1865d", openalex = "W2045730984", references = "doi1010160009254177900419, doi1010160016703780901556, doi101038293289a0, doi101039jr9470000562, doi10106311746492, doi101146annurevea05050177000433, doi1013062f91976516ce11d78645000102c1865d, doi10130683d9142516c711d78645000102c1865d, doi10130683d91f0616c711d78645000102c1865d, openalexw1558677347, shibaoka1978hydrocarbon" } @article{kantsler1983hydrocarbon, author = "Kantsler, A. J. and Prudence, T. J. C. and Cook, A. C. and Zwigulis, M.", title = "HYDROCARBON HABITAT OF THE COOPER/EROMANGA BASIN, AUSTRALIA", year = "1983", journal = "The APPEA Journal", abstract = "The Cooper Basin is a complex intracratonic basin containing a Permian-Triassic succession which is uncomformably overlain by Jurassic-Cretaceous sediments of the Eromanga Basin. Abundant inertinite-rich humic source rocks in the Permian coal measures sequence have sourced some 3TCF recoverable gas and 300 million barrels recoverable natural gas liquids and oil found to date in Permian sandstones. Locally developed vitrinitic and exinite-rich humic source rocks in the Jurassic to Lower Cretaceous section have, together with Permian source rocks, contributed to a further 60 million barrels of recoverable oil found in fluvial Jurassic-Cretaceous sandstones. Maturity trends vary across the basin in response to a complex thermal history, resulting in a present-day geothermal gradient which ranges from 3.0°C/100 m to 6.0°C/100 m. Permian source rocks are generally mature to postmature for oil generation, and oil/condensate-prone and dry gas-prone kitchens exist in separate depositional troughs. Jurassic source rocks generally range from immature to mature but are postmature in the central Nappamerri Trough. The Nappamerri Trough is considered to have been the most prolific Jurassic oil kitchen because of the mature character of the crudes found in Jurassic reservoirs around its flanks. Outside the central Nappamerri Trough, maturation modelling studies show that most hydrocarbon generation followed rapid subsidence during the Cenomanian. Most syndepositional Permian structures are favourably located in time and space to receive this hydrocarbon charge. Late formed structures (Mid-Late Tertiary) are less favourably situated and are rarely filled to spill point. The high CO2 contents of the Permian gas (up to 50 percent) may be related to maturation of the humic Permian source rocks and thermal degradation of Permian crudes. However, the high δ13C of the CO2 (av. −6.9 percent) suggests some mixing with CO2 derived from thermal breakdown of carbonates within both the prospective sequence and economic basement.", url = "https://doi.org/10.1071/aj82008", doi = "10.1071/aj82008", number = "1", openalex = "W4238310343", pages = "75-92", volume = "23" } @incollection{kantsler1984hydrocarbon, author = "Kantsler, A.J. and Prudence, T.J.C. and Cook, A. C. and Zwigulis, M.", title = "Hydrocarbon Habitat of the Cooper/Eromanga Basin, Australia", year = "1984", booktitle = "Petroleum Geochemistry and Basin Evaluation", url = "https://doi.org/10.1306/m35439c21", doi = "10.1306/m35439c21", openalex = "W1549239232" } @article{doi101306ad462bc316f711d78645000102c1865d, author = "Shanmugam, G.", title = "Significance of Coniferous Rain Forests and Related Organic Matter in Generating Commercial Quantities of Oil, Gippsland Basin, Australia1", year = "1985", journal = "AAPG Bulletin", abstract = "ABSTRACT Contrary to the conventional belief that humic coal generates primarily gas, 3 billion bbl of recoverable oil has been discovered in the humic coaly succession of the fluviodeltaic Latrobe Group (Upper Cretaceous-Tertiary) that serves as both the reservoir and the source for hydrocarbons in the offshore Gippsland basin of southeastern Australia. Evidence for generation of liquid hydrocarbons from the coaly succession includes: (1) similarity of n-alkane distribution in the oil and in the coal extracts; (2) high wax content of oil (up to 27\% by weight); (3) high ratio of pristane/phytane in oil (5-6); and (4) dominance of C29 steranes in the oil. In the Gippsland basin, coniferous rain forests dominated by kauri vegetation flourished in a raised bog setting. Present temperate climate and kauri vegetation of New Zealand are considered to be the modern analog to the Gippsland basin. The coniferous vegetation provided large quantities of hydrogen-rich exinite macerals, such as cutinite and resinite, with potential to generate oil. High rainfall, raised ground-water level, low oxygen, high acidity, and low-nutrient conditions of a raised bog setting were suitable for preserving organic matter. A comparison of gas chromatograms of oils in the Gippsland basin with gas chromatograms of oils generated by hydrous pyrolysis in the laboratory from the immature source rocks suggests that the paraffinic fraction of the oil was derived from coal, and the naphthenic fraction was derived chiefly from resin.", url = "https://doi.org/10.1306/ad462bc3-16f7-11d7-8645000102c1865d", doi = "10.1306/ad462bc3-16f7-11d7-8645000102c1865d", openalex = "W2021207480", references = "doi1010160016703769900404, doi1010160016703779902576, doi1010160031018282900840, doi1010160031018284900373, doi101071aj70012, doi101126science2034383897, doi10130683d9142516c711d78645000102c1865d, doi10130683d91f5116c711d78645000102c1865d, doi1023072257999, doi102973dsdpproc291171975, doi104319lo19671210079, hocking1972geologic, openalexw1558677347, openalexw296468733, openalexw364087571, shibaoka1978hydrocarbon" } @article{jbwillcox1990deep, author = "J. B. Willcox, J. B. Colwell, P. E.", title = "Deep Structure of the Gippsland Basin, Australia: Implications for Hydrocarbon Exploration: ABSTRACT", year = "1990", journal = "AAPG Bulletin", url = "https://doi.org/10.1306/44b4c04e-170a-11d7-8645000102c1865d", doi = "10.1306/44b4c04e-170a-11d7-8645000102c1865d", openalex = "W2328694126", volume = "74" } @book{openalexw1980909228, author = "Allen, Philip A. and Allen, J.R.L.", title = "Basin Analysis: Principles and Applications", year = "1990", abstract = "PART 1: THE FOUNDATIONS OF SEDIMENTARY BASINS:. Chapter 1 Basins in their plate tectonic environment. Summary. 1.1 Compositional zonation of the Earth. 1.2 Rheological zonation of the Earth. 1.3 Plate motion. 1.4 Classification schemes of sedimentary basins. Chapter 2 The physical state of the lithosphere. Summary. 2.1 Stress and strain. 2.2 Heat flow: conduction and convection. 2.3 Gravity and isostasy. 2.4 Rock rheology. PART 2: THE MECHANICS OF SEDIMENTARY BASIN FORMATION:. Chapter 3 Basins due to lithospheric stretching. Summary. 3.1 Introduction to rifts, failed rifts and passive continental margins. 3.2 Geological and geophysical observations in regions of continental extension. 3.3 Introduction to models of continental extension. 3.4 Uniform stretching of the continental lithosphere. 3.5 Modifications to the uniform stretching model. 3.6 A dynamical approach to lithospheric extension. 3.7 Mantle plumes and igneous activity associated with continental extension. 3.8 Estimation of the stretch factor and strain rate history. Chapter 4 Basins due to flexure. Summary. 4.1 Basic observations in regions of lithospheric flexure. 4.2 Flexure of the lithosphere: geometry of the deflection. 4.3 Flexural rigidity of the oceanic and continental lithosphere. 4.4 Lithospheric buckling. 4.5 The dynamics of orogenic wedges. 4.6 The modelling of foreland basins. Chapter 5 Effects of mantle dynamics. Summary. 5.1 Fundamentals and observations. 5.2 Dynamic topography. Chapter 6 Basins associated with strike-slip deformation. Summary. 6.1 Overview. 6.2 The structural pattern of strike-slip fault systems. 6.3 Basins in strike-slip zones. PART 3 THE SEDIMENTARY BASIN-FILL:. Chapter 7 The sediment routing system. Summary. 7.1 Introduction. 7.2 Weathering. 7.3 Terrestrial sediment and solute yields. 7.4 Measurements of erosion rates. 7.5 The functioning of sediment routing systems. Chapter 8 Basin stratigraphy. Summary. 8.1 A primer on process stratigraphy. 8.2 Stratigraphic cycles: definition and recognition. 8.3 Driving mechanisms for stratigraphic patterns. 8.4 Numerical simulation of stratigraphy. 8.5 Depositional systems. 8.6 Relation of depositional style to basin setting. Chapter 9 Subsidence and thermal history. Summary. 9.1 Introduction to 'geohistory analysis'. 9.2 Porosity loss during basin subsidence. 9.3 Subsidence history and backstripping. 9.4 Introduction to thermal history. 9.5 Theory: the Arrhenius equation and maturation indices. 9.6 Factors influencing temperatures and palaeotemperatures in sedimentary basins. 9.7 Measurements of thermal maturity in sedimentary basins. 9.8 Application of thermal maturity measurements. 9.9 Geothermal and palaeogeothermal signatures of basin types. PART 4 APPLICATION TO PETROLEUM PLAY ASSESSMENT:. Chapter 10 The petroleum play. Summary. 10.1 From basin analysis to play concept. 10.2 The petroleum system and play concept. 10.3 The petroleum charge system. 10.4 The reservoir. 10.5 The regional topseal. 10.6 The trap. References. Index", openalex = "W1980909228" } @incollection{crossref1991evaporite, title = "Evaporite Basin Analysis", year = "1991", booktitle = "Sedimentary and Diagenetic Mineral Deposits", url = "https://doi.org/10.5382/rev.05.12", doi = "10.5382/rev.05.12", pages = "159-169" } @article{moore1992integrated, author = "Moore, P. S. and Burns, B. J. and Emmett, J. K. and Guthrie, D. A.", title = "INTEGRATED SOURCE, MATURATION AND MIGRATION ANALYSIS, GIPPSLAND BASIN, AUSTRALIA", year = "1992", journal = "The APEA Journal", abstract = "Biomarker geochemistry, maturation modelling and migration pathway analysis have been used in a new, integrated analysis of the Gippsland Basin. The analysis has resulted in the development of a predictive model for hydrocarbon charge and oil versus gas split. The study was carried out in 4 parts: analytical geochemistry, source distribution mapping, maturation modelling and migration pathway analysis. New geochemical biomarker studies confirm a non-marine source for the oils, but place peak oil generation in the upper part of the traditional oil window. Gas in the basin is mainly derived from overmature source rocks. Coals were recognised to contribute significantly to oil generation. The source rock thickness and distribution for the entire basin were mapped using analytical techniques plus wireline log analysis, coupled with seismic structural mapping and facies analysis. Prime oil-prone source rocks were found to be located in the lower coastal plain depositional environment. Extrapolations were necessary for older rocks, using stratigraphic models. Maturation modelling modelling of selected wells and synclines was carried out and an overall basin model constructed. Post-structuring yields of oil and gas were also derived. A key result was the lack of post-structuring overmature gas generation in the oil prone southeastern part of the basin, owing to high palaeo-temperatures associated with earlier rifting. Analysis of present day and palaeo-migration pathways gave an excellent match between predicted oil versus gas ratios and discoveries, both geographically and stratigraphically. The tool is now being used in a predictive mode to highgrade basin prospectivity.", url = "https://doi.org/10.1071/aj91025", doi = "10.1071/aj91025", number = "1", openalex = "W2745579435", pages = "313-324", volume = "32" } @book{crossref1993computerized, title = "Computerized Basin Analysis", year = "1993", booktitle = "Computer Applications in the Earth Sciences", url = "https://doi.org/10.1007/978-1-4615-2826-5", doi = "10.1007/978-1-4615-2826-5" } @incollection{armentrout1999sedimentary, author = "Armentrout, John M.", title = "Sedimentary Basin Analysis", year = "1999", booktitle = "Exploring for Oil and Gas Traps", url = "https://doi.org/10.1306/trhbk624c4", doi = "10.1306/trhbk624c4" } @article{doi101046j14400952199900757x, author = "Tosolini, Anne-Marie P. and McLoughlin, Stephen and Drinnan, Andrew N.", title = "Stratigraphy and fluvial sedimentary facies of the Neocomian lower Strzelecki Group, Gippsland Basin, Victoria", year = "1999", journal = "Australian Journal of Earth Sciences", abstract = "The Strzelecki Group incorporates Berriasian to Albian, fluvial sediments deposited in the Gippsland Basin during initial rifting between Australia and Antarctica. Neocomian strata of the lowermost Strzelecki Group are assigned to the Tyers River Subgroup (exposed in the Tyers area) and the Rhyll Arkose (exposed on Phillip Island and the Mornington Peninsula). The Tyers River Subgroup incorporates two formations: Tyers Conglomerate and Rintoul Creek Formation. The latter is subdivided into the Locmany and Exalt Members. Ten fluvial sedimentary facies are identified in the lowermost Strzelecki Group: two gravelly facies; four sandy facies; and four mudrock facies. Associations of these facies indicate: (i) prevalence of gravelly braided‐river and alluvial‐fan settings during deposition of the Tyers Conglomerate; (ii) more sluggish, sandy braided to meandering fluvial systems during Locmany Member sedimentation; and (iii) a return to active, sandy, braided‐river settings for deposition of the Exalt Member. The Tyers Conglomerate and Rhyll Arkose rest on an irregular erosional surface incised into Palaeozoic rocks of the Lachlan Fold Belt. The overlying Rintoul Creek Formation incorporates more mature sediments where lithofacies associations varied according to base‐level change, variations in subsidence rates, and/or tectonic uplift of the principal sedimentsource terranes to the northwest.", url = "https://doi.org/10.1046/j.1440-0952.1999.00757.x", doi = "10.1046/j.1440-0952.1999.00757.x", openalex = "W2012848802", references = "doi101071aj70012" } @article{bernecker2001hydrocarbon, author = "Bernecker, T. and Woollands, M.A. and Wong, D. and Moore, D.H. and Smith, M.A.", title = "HYDROCARBON PROSPECTIVITY OF THE DEEPWATER GIPPSLAND BASIN, VICTORIA, AUSTRALIA", year = "2001", journal = "The APPEA Journal", abstract = "After 35 years of successful exploration and development, the Gippsland Basin is perceived as a mature basin. Several world class fields have produced 3.6 billion (109) BBL (569 GL) oil and 5.2 TCF (148 Gm3) gas. Without additional discoveries, it is predicted that further significant decline in production will occur in the next decade. However, the Gippsland Basin is still relatively underexplored when compared to other prolific hydrocarbon provinces. Large areas are undrilled, particularly in the eastern deepwater part of the basin. Here, an interpretation of new regional aeromagnetic and deep-water seismic data sets, acquired through State and Federal government initiatives, together with stratigraphic, sedimentological and source rock maturation modelling studies have been used to delineate potential petroleum systems. In the currently gazetted deepwater blocks, eight structural trapping trends are present, each with a range of play types and considerable potential for both oil and gas. These include major channel incision plays, uplifted anticlinal and collapsed structures that contain sequences of marine sandstones and shales (deepwater analogues of the Marlin and Turrum fields), as well as large marine shale-draped basement horsts. The study has delineated an extensive near-shore marine, lower coastal plain and deltaic facies association in the Golden Beach Subgroup. These Late Cretaceous strata are comparable to similar facies of the Tertiary Latrobe Siliciclastics and extend potential source rock distribution beyond that of previous assessments. In the western portion of the blocks, overburden is thick enough to drive hydrocarbon generation and expulsion. The strata above large areas of the source kitchen generally dip to the north and west, promoting migration further into the gazetted areas. Much of the basin’s deepwater area, thus, shares the deeper stratigraphy and favourable subsidence history of the shallow water producing areas. Future exploration and production efforts will, however, be challenged by the 200–2500 m water-depths and local steep bathymetric gradients, which affect prospect depth conversion and the feasibility of development projects in the case of successful exploration.", url = "https://doi.org/10.1071/aj00005", doi = "10.1071/aj00005", number = "1", openalex = "W2738745763", pages = "91-113", volume = "41" } @misc{crossref2003basin, title = "Basin Analysis", year = "2003", booktitle = "Principles of Stratigraphy", url = "https://doi.org/10.1002/9780470694015.ch8", doi = "10.1002/9780470694015.ch8", pages = "171-185" } @article{doi101046j14400952200301004x, author = "Holdgate, G. R. and Wallace, Malcolm W. and Gallagher, Stephen J. and Smith, Andrew J. and Keene, J. B. and Moore, D. H. and Shafik, Samir", title = "Plio‐Pleistocene tectonics and eustasy in the Gippsland Basin, southeast Australia: Evidence from magnetic imagery and marine geological data", year = "2003", journal = "Australian Journal of Earth Sciences", abstract = "The Pliocene and Pleistocene sediments of the Gippsland shelf are dominated by mixed carbonates and siliciclastics. From a detailed stratigraphic study that combines conventional marine geology techniques with magnetic imagery, the Late Neogene tectonic and eustatic history can be interpreted and correlated to the onshore section. Stratigraphic analyses of eight oil and gasfield foundation bores drilled to 150 m below the seabed revealed three principal facies types: (i) Facies A is fine‐grained limestone and limey marl deeper than 50 m below the seabed, of Late Pliocene age (nannofossil zones CN11–12); (ii) Facies B is a fine‐coarse pebble quartz‐carbonate sand that occurs 10–50 m below the seabed in the inner shelf, grading down into Facies A in wells in the outer shelf, and is of Early‐Middle Pleistocene age (nannofossil subzones CN13a-14b: ca 1.95–0.26 Ma); and (iii) discontinuous horizons of Facies C composed of carbonate‐poor carbonaceous and micaceous fine quartz sand occurring 10–50 m below the seabed. The sparse benthic foraminifers in Facies C are inner shelf or Gippsland (euryhaline) Lakes forms. Holocene sands dominate the upper 1.5–2.5 m of the Gippsland shelf and disconformably overlie cemented limestones with aragonite dissolution, indicating previous exposure to meteoric water. Nannofossil dating of the limestones indicates ages within subzone CN14b (dated between ca 0.26 and 0.47 Ma). Airborne magnetic imaging across the Gippsland shelf and onshore provides details of buried magnetic palaeoriver channels and barrier systems. The river systems trend south‐southeast from the Snowy, Tambo, Mitchell, Avon, Macalister and Latrobe Rivers across the shelf. Sparker seismic surveys show the magnetic palaeochannels as seismic ‘smudges’ 20–40 m below the seabed. They appear to correspond to Facies C lenses (i.e. are Early to Middle Pleistocene features). Magnetic palaeobarrier systems trending south‐southwest in the inner shelf and onshore beneath the Gippsland Lakes are orientated 15° different to the modern Ninety Mile Beach barrier trend. Offshore, they correlate stratigraphically to progradation packages of Facies B. Analysis of bore data in the adjacent onshore Gippsland Lakes suggests that a Pliocene barrier sequence 100–120 m below surface is overlain by fluvial sand‐gravel and lacustrine mud facies. The ferruginous sandstone beds resemble offshore Facies C, and are located where magnetic palaeoriver channel systems occur, implying Early to Middle Pleistocene ages. Presence of the estuarine bivalve Anadara trapezia in the upper lacustrine mud facies suggests that the Gippsland Lakes/Ninety Mile Beach‐type barriers developed over the past 0.2 million years. Further inland, magnetic river channels that cut across present‐day uplifted structures, such as the Baragwanath Anticline, suggest that onshore Gippsland uplift continued into the Middle Pleistocene.", url = "https://doi.org/10.1046/j.1440-0952.2003.01004.x", doi = "10.1046/j.1440-0952.2003.01004.x", openalex = "W2025653188", references = "doi101071aj70012, hocking1972geologic" } @article{mckenna2006geothermal, author = "McKenna, Jason R. and Beardsmore, Graeme", title = "Geothermal Potential associated with Hydrocarbon Production, Cooper Basin, Australia", year = "2006", journal = "ASEG Extended Abstracts", url = "https://doi.org/10.1071/aseg2006ab108", doi = "10.1071/aseg2006ab108", number = "1", openalex = "W2332670684", pages = "1-1", volume = "2006" } @article{doi1021741874834100801010001, author = "Mavromatidis, Angelos and Soupios, Pantelis", title = "Review of Exhumation and Implications for Hydrocarbon Exploration in Australia", year = "2008", journal = "The Open Petroleum Engineering Journal", abstract = "The subsidence history of sedimentary basins is recorded and can be relatively easily reconstructed from the preserved stratigraphic sequence. Uplift events, above sedimentary base level are expressed only by hiatuses or unconformities. Hence, quantifying the exhumation associated with uplift is intrinsically more problematic than quantifying the burial associated with the subsidence. Detailed study of the exhumation in basins is of particular significance since can provide crucial information about the petroleum exploration and for investigating the dynamic driving forces of basin uplift events. The aim of this article is to evaluate the magnitudes of exhumation in two well known petroliferous basins, the Cooper-Eromanga Basins of South Australia and Queensland, based on different techniques and to consider the implications for petroleum exploration.", url = "https://doi.org/10.2174/1874834100801010001", doi = "10.2174/1874834100801010001", openalex = "W2144664905", references = "kantsler1983hydrocarbon" } @article{liu2010hydrocarbon, author = "Liu, Keyu and Eadington, Peter and Mills, David and Kempton, Richard and Volk, Herbert and O’Brien, Geoffrey and Tingate, Peter and Goldie Divko, Louise and Harrison, Michael", title = "Hydrocarbon charge history of the Gippsland Basin*", year = "2010", journal = "The APPEA Journal", abstract = "As part of a larger petroleum system analysis and resource re-evaluation research program in the Gippsland Basin, over 400 samples from 29 selected wells in the Gippsland Basin were investigated using quantitative fluorescence techniques developed by CSIRO Petroleum, including the quantitative grain fluorescence (QGF) and QGF on extracts (QGF-E) and the total scanning fluorescence (TSF) techniques. Preliminary results have provided new insight into the hydrocarbon migration and charge history of the Gippsland Basin. The investigation has revealed: widespread occurrence of palaeo oil columns in some of the major gas fields, indicating that a significant amount of oil was charged into these reservoirs prior to a subsequent gas accumulation;that some of the current oil intervals appear to have received a relatively late oil charge, either through new charge or through palaeo oil re-distribution due to adjustments within the petroleum system;palaeo oil columns appear to be restricted to a certain distance range from the major source kitchens; and,evidence of a sequential oil migration and displacement along structural highs where reservoirs distal to the source kitchens received progressively lighter and more mature palaeo oils. These findings are consistent with the oil generation and migration model proposed by O’Brien et al (2008). Fluid inclusion petrographic investigations and molecular composition of inclusions (MCI) analysis are currently underway that will provide additional information on the hydrocarbon charge history in the Gippsland Basin.", url = "https://doi.org/10.1071/aj09093", doi = "10.1071/aj09093", number = "2", openalex = "W2748626350", pages = "729-729", volume = "50", references = "doi101016jorggeochem200502008" } @article{openalexw2500434169, author = "Rollet, Nadège and Higgins, Karen and Petkovic, Peter and Hackney, Ron and Fraser, Geoff", title = "Integrated assessment of the Capel and Faust basins, offshore eastern Australia", year = "2010", abstract = "issue 99 sept 2010 A recent assessment carried out by Geoscience Australia has provided new insights into the geological evolution and petroleum prospectivity of the Capel and Faust basins. These remote deepwater basins, located about 800 kilometres off the east coast of Australia in water depths of 1300 to 2500 metres (figure 1), have previously seen little scientific or petroleum exploration effort. This assessment was carried out under the Australian Government’s Offshore Energy Security Program as part of Geoscience Australia’s continuing efforts to identify a new offshore petroleum province and deliver pre-competitive geoscience information (AusGeo News 84).", openalex = "W2500434169", references = "bernecker2001hydrocarbon" } @article{doi101016jtecto201204007, author = "Lindsay, Mark and Aillères, Laurent and Jessell, Mark and de Kemp, E A and Betts, Peter", title = "Locating and quantifying geological uncertainty in three-dimensional models: Analysis of the Gippsland Basin, southeastern Australia", year = "2012", journal = "Tectonophysics", url = "https://doi.org/10.1016/j.tecto.2012.04.007", doi = "10.1016/j.tecto.2012.04.007", openalex = "W1964396403", references = "bernecker2001hydrocarbon, doi101016jpepi200806014" } @article{doi101080081200992013755567, author = "O'Brien, Geoffrey and Tingate, Peter and Divko, L. M. Goldie and Miranda, J. A. and Campi, Monica and Liu, K.", title = "Basin-scale fluid flow in the Gippsland Basin: implications for geological carbon storage", year = "2013", journal = "Australian Journal of Earth Sciences", abstract = "Petroleum systems analysis has been carried out to better understand the geological CO2 storage potential of the Gippsland Basin. From a regional perspective, the hydrocarbon migration architecture of the basin is interpreted to be dominated by two highly connected, filled-to-spill, hydrocarbon fairways; the northern (gas-dominated) and southern (oil-dominated) fill-spill chains, forming a convergent system that extends onshore along the Golden Beach Fill-Spill Chain (GBFSC). A separate oil-dominated Fill-Spill Chain, the Dolphin-Perch Fill-Spill Chain (DPFSC), is identified offshore to the southwest. Two broad flanking provinces, the Northerly Migration Province (NMP) and Southerly Migration Province (SMP), are also identified. Both provinces have broadly ramp-like geometries and relatively low dips. Migration across these provinces is not focused, and hence multiple pathways are present across a wide area. An understanding of the hydrocarbon systems in the basin can be used for characterising the potential for CO2 storage. Previous studies have shown that the top seal potential of the offshore Gippsland Basin is suited to geological carbon storage and that large areas are prospective as storage regions. However, the linked nature of the fluid flow systems and the focused fluid flow fairways between areas of high storage potential and leaky systems onshore will require both a good regional geological understanding and informed resource management.", url = "https://doi.org/10.1080/08120099.2013.755567", doi = "10.1080/08120099.2013.755567", openalex = "W1971990693", references = "liu2010hydrocarbon" } @misc{crossref2014basin, title = "BASIN ANALYSIS", year = "2014", booktitle = "Encyclopedia of Environmental Change", url = "https://doi.org/10.4135/9781446247501.n364", doi = "10.4135/9781446247501.n364" } @article{doi101016jgsf201508001, author = "Singh, Prakash K. and Singh, Vijay Kumar and Rajak, P. K. and Singh, Mahendra and Naik, A. S. and Raju, S.V. and Mohanty, Debadutta", title = "Eocene lignites from Cambay basin, Western India: An excellent source of hydrocarbon", year = "2015", journal = "Geoscience Frontiers", abstract = "In the present paper lignites from the Cambay basin have been studied for their hydrocarbon potential. The samples were collected from three lignite fields–Vastan, Rajpardi and Tadkeshwar, and were investigated by petrography, chemical analyses and Rock-Eval pyrolysis. The results are well comparable with the empirically derived values. The study reveals that these ‘low rank C’ lignites are exceedingly rich in reactive macerals (huminite + liptinite) while inertinite occurs in low concentration. These high volatile lignites generally have low ash yield except in few sections. The Rock-Eval data indicates the dominance of kerogen type-III with a little bit of type-II. The study reveals that the lignites of Vastan (lower and upper seams) and Tadkeshwar upper seam are more gas-prone while Rajpardi and Tadkeshwar lower seams are oil-prone. Further, the fixed hydrocarbons are several times higher than the free hydrocarbons. The relation between TOC and fixed hydrocarbon indicates that these lignites are excellent source rock for hydrocarbon which could be obtained mainly through thermal cracking. The empirically derived values reveal a high conversion (94–96\%) and high oil yield (64–66\%) for these lignites.", url = "https://doi.org/10.1016/j.gsf.2015.08.001", doi = "10.1016/j.gsf.2015.08.001", openalex = "W1452418695", references = "moore1992integrated" } @article{doi101016jorggeochem201511001, author = "Abbassi, Soumaya and Edwards, Dianne S. and George, Simon C. and Volk, Herbert and Mahlstedt, Nicolaj and di Primio, Rolando and Horsfield, Brian", title = "Petroleum potential and kinetic models for hydrocarbon generation from the Upper Cretaceous to Paleogene Latrobe Group coals and shales in the Gippsland Basin, Australia", year = "2015", journal = "Organic Geochemistry", url = "https://doi.org/10.1016/j.orggeochem.2015.11.001", doi = "10.1016/j.orggeochem.2015.11.001", openalex = "W2111705365", references = "doi101071aj69007" } @article{doi101111bre12146, author = "Ziesch, Jennifer and Aruffo, Chiara M. and Tanner, David C. and Beilecke, Thies and Dance, Tess and Henk, Andreas and Weber, Bastian and Tenthorey, Eric and Lippmann, Andrea and Krawczyk, Charlotte M.", title = "Geological structure and kinematics of normal faults in the Otway Basin, Australia, based on quantitative analysis of 3‐D seismic reflection data", year = "2015", journal = "Basin Research", abstract = "Abstract The Otway Basin in the south of Victoria, Australia underwent three phases of deformation during breakup of the southern Australian margin. We assess the geometry and kinematics of faulting in the basin by analysing a 3‐D reflection seismic volume. Eight stratigraphic horizons and 24 SW ‐dipping normal faults as well as subordinate antithetic faults were interpreted. This resulted in a high‐resolution geological 3‐D model (ca. 8 km × 7 km × 4 km depth) that we present as a supplementary 3‐D PDF (Data S1). We identified hard‐ and soft‐linking fault connections over the entire area, such as antithetic faults and relay ramps, respectively. Most major faults were continuously active from Early to Late Cretaceous, with two faults in the northern part of the study area active until at least the Oligocene. Allan maps of faults show tectonic activity continuously waned over this time period. Isopach maps of stratigraphic volumes quantify the amount of syn‐sedimentary movement that is characteristic of passive margins, such as the Otway Basin. We show that the faults possess strong corrugations (with amplitudes above the seismic resolution), which we illustrated by novel techniques, such as cylindricity and curvature. We argue that the corrugations are produced by sutures between sub‐vertical fault segments and this morphology was maintained during fault growth. Thus, they can be used to indicate the kinematics vector of the fault movement. This evidences, together with left‐stepping relay ramps, that 40\% of the faults had a small component (up to 25°) of dextral oblique slip as well as normal (dip‐slip) movement.", url = "https://doi.org/10.1111/bre.12146", doi = "10.1111/bre.12146", openalex = "W1930180229", references = "moore1992integrated" } @article{doi101016jcoal201806025, author = "Jiang, Lian and George, Simon C.", title = "Biomarker signatures of Upper Cretaceous Latrobe Group hydrocarbon source rocks, Gippsland Basin, Australia: Distribution and palaeoenvironment significance of aliphatic hydrocarbons", year = "2018", journal = "International Journal of Coal Geology", url = "https://doi.org/10.1016/j.coal.2018.06.025", doi = "10.1016/j.coal.2018.06.025", openalex = "W2875103904", references = "moore1992integrated" } @article{doi101016jsedgeo201907007, author = "Korasidis, Vera A. and Wallace, Malcolm W. and Dickinson, Julie A. and Hoffman, Nick", title = "Depositional setting for Eocene seat earths and related facies of the Gippsland Basin, Australia", year = "2019", journal = "Sedimentary Geology", url = "https://doi.org/10.1016/j.sedgeo.2019.07.007", doi = "10.1016/j.sedgeo.2019.07.007", openalex = "W2966438438", references = "doi101071aj70012, hocking1972geologic" } @article{hall2019hydrocarbon, author = "Hall, Lisa S. and Palu, Tehani J. and Murray, Andrew P. and Boreham, Christopher J. and Edwards, Dianne S. and Hill, Anthony J. and Troup, Alison", title = "Hydrocarbon prospectivity of the Cooper Basin, Australia", year = "2019", journal = "AAPG Bulletin", abstract = "The Pennsylvanian–Middle Triassic Cooper Basin is Australia’s premier conventional onshore hydrocarbon-producing province. The basin also hosts a range of unconventional gas play types, including basin-centered gas and tight gas accumulations, deep dry coal gas associated with the Patchawarra and Toolachee Formations, and the Murteree and Roseneath shale gas plays. This study used petroleum systems analysis to investigate the maturity and generation potential of 10 Permian source rocks in the Cooper Basin. A deterministic petroleum systems model was used to quantify the volume of expelled and retained hydrocarbons, estimated at 1272 billion BOE (512 billion bbl and 760 billion BOE) and 977 billion BOE (362 billion bbl and 615 billion BOE), respectively. Monte Carlo simulations were used to quantify the uncertainty in volumes generated and to demonstrate the sensitivity of these results to variations in source-rock characteristics. The large total generation potential of the Cooper Basin and the broad distribution of the Permian source kitchen highlight the basin’s significance as a world-class hydrocarbon province. The large disparity between the calculated volume of hydrocarbons generated and the volume so far found in reservoirs indicates the potential for large volumes to remain within the basin, despite significant losses from leakage and water washing. The hydrocarbons expelled have provided abundant charge to both conventional accumulations and to the tight and basin-centered gas plays, and the broad spatial distribution of hydrocarbons remaining within the source rocks, especially those within the Toolachee and Patchawarra Formations, suggests the potential for widespread shale and deep dry coal plays.", url = "https://doi.org/10.1306/05111817249", doi = "10.1306/05111817249", number = "1", openalex = "W2807279711", pages = "31-63", volume = "103", references = "doi1010022013jb010626, doi1010160016703789901361, doi1010160016703792902155, doi1010160264817295969045, doi101016026481729598381e, doi101016026481729598382f, doi101016s0146638002001833, doi101017cbo9780511606021, doi10103819953, openalexw1980909228" } @article{doi101016jmarpetgeo2020104243, author = "Mahon, Elizabeth and Wallace, Malcolm W.", title = "Cenozoic structural history of the Gippsland Basin: Early Oligocene onset for compressional tectonics in SE Australia", year = "2020", journal = "Marine and Petroleum Geology", url = "https://doi.org/10.1016/j.marpetgeo.2020.104243", doi = "10.1016/j.marpetgeo.2020.104243", openalex = "W2998963053", references = "hocking1972geologic" } @incollection{crossref2021selected, title = "Selected basin analysis", year = "2021", booktitle = "Progress on Transboundary Water Cooperation Under the Water Convention", url = "https://doi.org/10.18356/9789210057899c012", doi = "10.18356/9789210057899c012", pages = "70-83" } @article{doi101071aj22084, author = "Boreham, Christopher J. and Edwards, Dianne S. and Feitz, Andrew and Murray, Andrew and Mahlstedt, Nicolaj and Horsfield, Brian", title = "Modelling of hydrogen gas generation from overmature organic matter in the Cooper Basin, Australia", year = "2023", journal = "The APPEA Journal", abstract = "A significant portion of planned energy and mineral resource investment into Australia is now for hydrogen (H2). Whether from fossil fuels with carbon capture and storage or from electrolysis of water using renewable energy, there is a price premium for manufactured hydrogen. The production of H2 from geological sources (geologic H2) could be more cost-effective. The majority of sources for geologic H2 are abiotic and their resource potential is largely unknown. Biogenic (microbial and thermogenic) sources also exist. The focus for this study is on a thermogenic source where chemical kinetics of H2 generation from the thermal breakdown of land-plant-derived organic matter has been applied within a petroleum system modelling framework for the Cooper Basin. Modelling of mid-Patchawarra Formation coals and shales, the main source rocks for petroleum, indicate that free H2 is available at maturities \>3.5\% vitrinite reflectance and that a large volume of free H2 is predicted to occur in a ‘sweet spot’ deep within the Nappamerri Trough. In-situ free H2 concentrations deep within the Nappamerri Trough are predicted to be comparable to methane concentrations in productive unconventional shale gas plays. Nevertheless, exploration drilling within the Cooper Basin’s depocentre is sparse and a deep H2 system remains largely untested.", url = "https://doi.org/10.1071/aj22084", doi = "10.1071/aj22084", openalex = "W4376105451", references = "hall2019hydrocarbon" } @incollection{crossref2025selected, title = "Selected basin analysis", year = "2025", booktitle = "Progress on Transboundary Water Cooperation Under the Water Convention", url = "https://doi.org/10.18356/9789211065022c012", doi = "10.18356/9789211065022c012", pages = "92-113" } @article{doi101071ep24240, author = "Wilkinson, Lindsey and Lavin, Ciarán and Davies, Clare E.", title = "Reservoir prediction in wave-dominated fluvio-deltaic systems using seismic sequence stratigraphic techniques, an example from the cretaceous Golden Beach Formation, offshore Gippsland Basin", year = "2025", journal = "Australian Energy Producers journal.", abstract = "Wave-dominated deltas are important hosts for global hydrocarbon reserves, containing significant volumes within good quality, laterally extensive sandstone reservoirs. These deltas often contain an ordered internal architecture with predictable facies distribution patterns identified at a detailed scale in outcrops such as the Cretaceous Blackhawk Formation of the Book Cliffs, Utah, USA. This predictability can be utilised to support reservoir characterisation and modelling in subsurface regions with limited well control and only seismic scale resolution, reducing risk and uncertainty in predicting hydrocarbon volumes. This study illustrates how detailed seismic mapping and attribute extractions were used to refine a sequence stratigraphic framework for a wave-dominated shoreline in the Gippsland Basin. The natural cyclicity of progradational, aggradational and transgressive systems was captured in this assessment, interpreted to have been driven by autocyclic switching, influenced by fluvial input and active extensional tectonism, reworked by waves. Integration of this detailed sequence stratigraphic framework with world class analogues was used to inform facies distributions, supporting predictions for reservoir distribution and quality away from well control.", url = "https://doi.org/10.1071/ep24240", doi = "10.1071/ep24240", openalex = "W4410576924", references = "bernecker2001hydrocarbon" }