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1
Djamaludin, I., and S. Brew. "Cooper basin azimuthal seismic." ASEG Extended Abstracts 2003, no. 2 (August 2003): 1. http://dx.doi.org/10.1071/aseg2003ab040.
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Heath, R. "EXPLORATION IN THE COOPER BASIN." APPEA Journal 29, no. 1 (1989): 366. http://dx.doi.org/10.1071/aj88031.
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The Cooper Basin is located in the northeastern corner of South Australia and in the southwestern part of Queensland. The basin constitutes an intracratonic depocentre of Permo- Triassic age. The Cooper Basin succession unconformably overlies Proterozoic basement as well as sediments and metasediments of the Cambro- Ordovician age. An unconformity separates in turn the Cooper succession from the overlying Jurassic- Cretaceous Eromanga Basin sediments.The Permo- Triassic succession comprises several cycles of fluvial sandstones, fluvio- deltaic coal measures and lacustrine shales. The coal measures contain abundant humic kerogen, comprising mainly inertinite and vitrinite with a small contribution of exinite. All hydrocarbon accumulations within the Cooper Basin are believed to have originated from these terrestrial source rocks.Exploration of the basin commenced in 1959 and, after several dry holes, the first commercial discovery of gas was made at Gidgealpa in 1963. To date, some 97 gas fields and 10 oil fields, containing recoverable reserves of 5 trillion cubic feet of gas and 300 million barrels recoverable natural gas liquids and oil, have been discovered in the Cooper Basin. Production is obtained from all sand- bearing units within the Cooper stratigraphic succession.The emphasis of exploration in the Cooper Basin is largely directed towards the assessment of four- way dip closures and three- way dip closures with fault control, but several stratigraphic prospects have been drilled. Furthermore, in the development phase of some gas fields a stratigraphic component of the hydrocarbon trapping mechanism has been recognised.Improvements in seismic acquisition and processing, combined with innovative thinking by the explorers, have facilitated the development of untested structural/stratigraphic plays with large reserves potential. Exploration for the four- and three- way dip closure plays in the Cooper Basin is now at a mature stage. However, reserves objectives are expected to continue to be met, with the expectation of a continuing high success rate.Selected new plays are expected to be tested within a continuing active exploration program as exploration for oil and gas in the Cooper Basin refines the search for the subtle trap.
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Seweryn, Witold, Dave Cockshell, Peter Hough, and Steve Fabjancic. "Time Slicing the Cooper Basin." ASEG Extended Abstracts 2016, no. 1 (December 2016): 1–6. http://dx.doi.org/10.1071/aseg2016ab132.
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Hall, Lisa, Tehani Palu, Chris Boreham, Dianne Edwards, Tony Hill, Alison Troup, and Paul Henson. "Cooper Basin source rock atlas." APPEA Journal 56, no. 2 (2016): 594. http://dx.doi.org/10.1071/aj15100.
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The Australian Petroleum Source Rocks Mapping project is a new study to improve understanding of the petroleum resource potential of Australia’s sedimentary basins. The Permian source rocks of the Cooper Basin, Australia’s premier onshore hydrocarbon-producing province, are the first to be assessed for this project. Quantifying the spatial distribution and petroleum generation potential of these source rocks is critical for understanding both the conventional and unconventional hydrocarbon prospectivity of the basin. Source rock occurrence, thickness, quality and maturity are mapped across the basin, and original source quality maps prior to the onset of generation are calculated. Source rock property mapping results and basin-specific kinetics are integrated with 1D thermal history models and a 3D basin model to create a regional multi-1D petroleum systems model for the basin. The modelling outputs quantify both the spatial distribution and total maximum hydrocarbon yield for 10 source rocks in the basin. Monte Carlo simulations are used to quantify the uncertainty associated with hydrocarbon yield and to highlight the sensitivity of results to each input parameter. The principal source rocks are the Permian coals and carbonaceous shales of the Gidgealpa Group, with highest potential yields from the Patchawarra Formation coals. The total generation potential of the Permian section highlights the significance of the basin as a world-class hydrocarbon province. The systematic workflow applied here demonstrates the importance of integrated geochemical and petroleum systems modelling studies as a predictive tool for understanding the petroleum resource potential of Australia’s sedimentary basins.
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Bednall, T. "COMPETITION LAWS IN THE COOPER BASIN." APPEA Journal 35, no. 1 (1995): 757. http://dx.doi.org/10.1071/aj94052.
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Competition laws in Australia are in the process of substantial reform. The major competition issues facing participants in the Cooper Basin: market definition, and competition between joint venturers are reviewed. The manner in which the Trade Practices Act has been applied to Cooper Basin producers is reviewed, proposed reforms to implement new national competition policy are outlined, and the likely impact which those reforms will have on the production and marketing of gas from the Cooper Basin are discussed.The likelihood, under reformed laws, of development of natural gas pipelines, open access, the difficulties of separate marketing of gas by joint venture parties, the potential for inter-basin competition in Australia, and the real issue of whether substantial benefits will flow to consumers of gas as a result of the application of new competition policies are evaluated.
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Lavering, L. H., V. L. Passmore, and I. M. Paton. "DISCOVERY AND EXPLOITATION OF NEW OILFIELDS IN THE COOPER-EROMANGA BASINS." APPEA Journal 26, no. 1 (1986): 250. http://dx.doi.org/10.1071/aj85024.
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Since 1975 the level of petroleum exploration in the Cooper-Eromanga basins has undergone an unprecedented expansion due to the discovery and development of an increasing number of oil reservoirs, largely in the Eromanga Basin sequence. The commercial incentive provided by the Commonwealth Government's Import Parity Pricing and excise arrangements have been instrumental in the lead up to and continuation of this series of discoveries.Three types of oil discovery in the Eromanga Basin sequence are evident; firstly, shallow pools above Cooper Basin gas fields; secondly, separate single-field discoveries in areas of limited exploration; and thirdly, as multifield discoveries along major structural trends. Exploitation of the Eromanga Basin oil discoveries has been made possible by a combination of rapid appraisal and development drilling and early commencement of production.The initial Eromanga Basin oil discoveries overlie major Cooper Basin gas fields and were located during appraisal and development drilling of deeper Cooper Basin gas reservoirs. Wildcat and appraisal drilling on Eromanga Basin prospects, such as Wancoocha and Narcoonowie, has upgraded the prospectivity of the Eromanga Basin sequence in the southern Cooper Basin—an area where earlier exploration for Cooper Basin gas was unsuccessful. Significant oil discoveries in Bodalla South 1 and Tintaburra 1, in the Queensland sector of the Eromanga Basin, have extended the range of exploration success and generated considerable interest in lesser known parts of the Eromanga Basin.Three successive phases of Cooper-Eromanga exploration have led to the present high level of success. Early exploration, before 1969, led to the initial discovery and development of Cooper Basin gas fields and was largely supported by the Petroleum Search Subsidy Acts (19571974). The results of the second phase, between 1970 and 1975, provided little encouragement to operators to extend exploration beyond the limits of the then known gas accumulations. In the decade since 1975, the oil potential of the Eromanga and parts of the Cooper Basin sequences has become a major factor in the exploration and development activity of the region. Since 1975, the favourable commercial conditions prevailing under the Import Parity Pricing scheme and the concessional crude oil excise arrangments for production from 'newly discovered' oilfields provided a significant incentive for development and exploitation of the post-1975 oil discoveries.
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Min, Ki-Bok, Linmao Xie, Hanna Kim, and Jaewon Lee. "EGS field case studies - UK Rosemanowes and Australian Cooper Basin projects." Journal of Korean Society For Rock Mechanics 24, no. 1 (February 28, 2014): 21–31. http://dx.doi.org/10.7474/tus.2014.24.1.021.
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Hall, Lisa, Tony Hill, Liuqi Wang, Dianne Edwards, Tehani Kuske, Alison Troup, and Chris Boreham. "Unconventional gas prospectivity of the Cooper Basin." APPEA Journal 55, no. 2 (2015): 428. http://dx.doi.org/10.1071/aj14063.
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The Cooper Basin is an Upper Carboniferous–Middle Triassic intracratonic basin in northeast SA and southwest Queensland. The basin is Australia's premier onshore hydrocarbon-producing province and is nationally significant due to its provision of domestic gas for the east coast gas market. Exploration activity in the region has recently expanded with numerous explorers pursuing newly identified unconventional hydrocarbon plays. While conventional gas and oil prospects can usually be identified by 3D seismic, the definition and extent of the undiscovered unconventional gas resources in the basin remain poorly understood. This extended abstract reviews the hydrocarbon prospectivity of the Cooper Basin with a focus on unconventional gas resources. Regional basin architecture, characterised through source rock distribution and quality, demonstrates the abundance of viable source rocks across the basin. Petroleum system modelling, incorporating new compositional kinetics, source quality and total organic carbon (TOC) map, highlight the variability in burial, thermal and hydrocarbon generation histories between depocentres. The study documents the extent of a number of unconventional gas play types, including the extensive basin-centred and tight gas accumulations in the Gidgealpa Group, deep-dry coal gas associated with the Patchawarra and Toolachee formations, as well as the less extensive shale gas plays in the Murteree and Roseneath shales.
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Hall, Lisa S., Tehani J. Palu, Andrew P. Murray, Christopher J. Boreham, Dianne S. Edwards, Anthony J. Hill, and Alison Troup. "Hydrocarbon prospectivity of the Cooper Basin, Australia." AAPG Bulletin 103, no. 1 (January 2019): 31–63. http://dx.doi.org/10.1306/05111817249.
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Alexander, R., A. V. Larcher, R. I. Kagi, and P. L. Price. "THE USE OF PLANT DERIVED BIOMARKERS FOR CORRELATION OF OILS WITH SOURCE ROCKS IN THE COOPER/EROMANGA BASIN SYSTEM, AUSTRALIA." APPEA Journal 28, no. 1 (1988): 310. http://dx.doi.org/10.1071/aj87024.
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Whether or not the sediments in the Eromanga Basin have generated petroleum is a problem of considerable commercial importance which remains contentious as it has not yet been resolved unequivocally. Sediments of the underlying Cooper Basin were deposited throughout the Permian and much of the Triassic, and deposition in the overlying Eromanga Basin commenced in the Early Jurassic and extended into the Cretaceous. As Araucariaceae (trees of the kauri pine group) assumed prominence for the first time in the Early to Middle Jurassic and were all but absent in older sediments, a promising approach would seem to be using the presence or absence of specific araucariacean chemical marker signatures as a means of distinguishing oils formed from source rocks in the Eromanga Basin from those derived from the underlying Cooper Basin sediments.The saturated and aromatic hydrocarbon compositions of the sediment extracts from the Cooper and Eromanga Basins have been examined to identify the distinctive fossil hydrocarbon markers derived from such resins. Sediments from the Eromanga Basin, which contain abundant micro-fossil remains of the araucariacean plants, contain diterpane hydrocarbons and aromatic hydrocarbons which bear a strong relationship to natural products in modern members of the Araucariaceae. Sediments from the Permo-Triassic Cooper Basin, which predate the Jurassic araucariacean flora, have different distributions of diterpane biomarkers and aromatic hydrocarbons.Many oils found in the Cooper/Eromanga region do not have the biological marker signatures of the Jurassic sediments and appear to be derived from the underlying Permian sediments; however, several oils contained in Jurassic to Cretaceous reservoirs show the araucariacean signature of the associated Jurassic to Early Cretaceous source rock sediments. It is likely, therefore, that these oils were sourced and reservoired within the Eromanga Basin and have not migrated from the Cooper Basin sequences below. Accordingly, exploration strategies in the Cooper Eromanga system should include prospects that could have been charged with oil from mature Jurassic/Early Cretaceous sediments of the Eromanga Basin.
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Tyiasning, Stephanie, and Dennis Cooke. "Anisotropy signatures in the Cooper Basin of Australia: Stress versus fractures." Interpretation 4, no. 2 (May 1, 2016): SE51—SE61. http://dx.doi.org/10.1190/int-2015-0131.1.
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Theoretically, vertical fractures and stress can create horizontal transverse isotropy (HTI) anisotropy on 3D seismic data. Determining if seismic HTI anisotropy is caused by stress or fractures can be important for mapping and understanding reservoir quality, especially in unconventional reservoirs. Our study area was the Cooper Basin of Australia. The Cooper Basin is Australia’s largest onshore oil and gas producing basin that consists of shale gas, basin-centered tight gas, and deep coal play. The Cooper Basin has unusually high tectonic stress, with most reservoirs in a strike-slip stress regime, but the deepest reservoirs are interpreted to be currently in a reverse-fault stress regime. The seismic data from the Cooper Basin exhibit HTI anisotropy. Our main objective was to determine if the HTI anisotropy was stress induced or fracture induced. We have compared migration velocity anisotropy and amplitude variation with offset anisotropy extracted from a high-quality 3D survey with a “ground truth” of dipole sonic logs, borehole breakout, and fractures interpreted from image logs. We came to the conclusion that the HTI seismic anisotropy in our study area is likely stress induced.
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Hughes, J. R., and S. R. Brew. "Recent seismic acquisition trials in the Cooper Basin." ASEG Extended Abstracts 2003, no. 2 (August 2003): 1. http://dx.doi.org/10.1071/aseg2003ab075.
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Hough, Peter, Dave Cockshell, Witold Seweryn, Keith Woollard, and Annette Peters. "Cooper Basin workstation data provision - pitfalls and progress." ASEG Extended Abstracts 2004, no. 1 (December 2004): 1–4. http://dx.doi.org/10.1071/aseg2004ab072.
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Tyiasning, Stephanie, and Dennis Cooke. "Uncovering Seismic HTI Anisotropy of the Cooper Basin." ASEG Extended Abstracts 2016, no. 1 (2016): 1. http://dx.doi.org/10.1071/aseg2016ab240.
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Kuang, K. S. "History and style of Cooper?Eromanga Basin structures." Exploration Geophysics 16, no. 2-3 (June 1985): 245–48. http://dx.doi.org/10.1071/eg985245.
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Bishop, Ian, and Steve Martucci. "WELL TUBULAR CORROSION IN THE COOPER/EROMANGA BASIN." APPEA Journal 31, no. 1 (1991): 404. http://dx.doi.org/10.1071/aj90034.
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In September 1987 the Della-1 gas well blew out at approximately 19.5m (64ft) abovesea level (42.7m (140 ft) KB) due to corrosion of the production casing and tubing.The production casing failure and other similar corrosion occurrences were considered to be due to sulphate-reducing bacteria which have been identified in a large number of wells in the Cooper Basin. It was considered possible that iron sulphide was being deposited on the casings in the surface-to-production casing annulus at the air/water interface promoting the formation of anodic sites and therefore corrosion.Further investigations of the evidence indicates that sulphate-reducing bacteria are not the major contributors to the corrosion as was initially believed. Field studies, laboratory analysis and ongoing well programs show that the process of differential aeration is the prime cause of the casing corrosion. Corrosion has been found to occur predominantly at a depth of between 18.3m (60 ft) and 36.6m (120 ft) above sea level and occurs over a band of 6.1 m (20 ft) to 9.1m (SO ft) in each well in conjunction with the external water table.As a result of this corrosion failure SANTOS has initiated a regular program of well maintenance, annulus inhibitor top-ups and pressure testing. A total of 315 wells have been tested to date, production casing corrosion problems have been identified in 35 wells, 31 wells have been repaired and four wells abandoned.
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Wecker, H. R. B., V. Ziolkowski, and G. D. Powis. "NEW GAS DISCOVERIES IN THE NORTHERN COOPER BASIN." APPEA Journal 36, no. 1 (1996): 104. http://dx.doi.org/10.1071/aj95006.
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Over the last two decades, minimal gas exploration was undertaken in the northeastern Cooper Basin. It was viewed the area held negligible gas potential due to the perceived absence of conventional anticlinal traps and the marginal reservoir quality of the Permian sandstones.With the award of permit ATP 549P to Mount Isa Mines Limited in mid-1993, available seismic and well data were reviewed to highlight potential fault-controlled traps in the region and to define areas likely to contain more favourable reservoir sandstones. A vibroseis seismic survey provided the initial prospects and leads inventory upon which the 1994 drilling program was based. Four prospects were tested resulting in three gas discoveries.Based on these encouraging results, an additional phase of seismic acquisition was completed to increase the prospect inventory. Thereafter, a five well program was undertaken. Whilst the two appraisal wells were successful, three wildcat wells failed due to ineffective trapping.A completion and testing program has been initiated to further evaluate the field discoveries.From an exploration viewpoint, the recognition of a consistently productive sandstone in the basal Toolachee Formation within a broad fairway across the eastern ATP 549P permit block was a significant result which has important implications for future activities. Within the fairway, gas flows varying from 0.4 MMcfd up to 6.0 MMcfd were measured on openhole tests. In addition, substantial gas volumes in low permeability sandstones within the Patchawarra Formation have been defined.These discoveries, coupled with the number of prospects and leads and the proposed gas pipeline to Mount Isa and to southeast Queensland markets, provide strong impetus to the continued evaluation of this northern extension of the Cooper Basin gas province.
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Ovenden, Bill. "Old rocks, new tricks: a reinvigorated Cooper Basin offers growth opportunity." APPEA Journal 59, no. 2 (2019): 928. http://dx.doi.org/10.1071/aj18248.
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The Cooper Basin spans north-east South Australia and south-west Queensland and is Australia’s largest integrated onshore oil and gas development. Santos and Delhi first discovered commercial gas in 1963. First oil was discovered in 1970. Since then, the Cooper Basin has become a strategically important processing and transportation hub for produced gas and liquids. Continuous investment in new technology, the use of existing infrastructure and, recently, an unrelenting drive to lower drilling and production costs has delivered a low-cost, high-margin producer for east coast domestic and liquefied natural gas (LNG) export markets. This improved operating performance has, in turn, offered Santos the opportunity to reassess ‘our backyard’. The Cooper Basin boasts many growth options, remaining and emerging. Seismic advances are providing improved imaging. Data management, the use of play-based exploration studies, innovative geoscience thinking and renewed investment risk appetite are playing key roles in the development of discovered resources and the exploration of new and emerging plays. Targeted wildcat exploration and appraisal programs, supported by low-cost operations, offer the potential to unlock significant remaining oil and gas resources. The Cooper Basin is poised for another stage of growth. This tangible potential emphasises the critical future role the basin is likely to continue to play as an onshore Australian hydrocarbon supply hub.
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Boreham, C. J., and R. E. Summons. "NEW INSIGHTS INTO THE ACTIVE PETROLEUM SYSTEMS IN THE COOPER AND EROMANGA BASINS, AUSTRALIA." APPEA Journal 39, no. 1 (1999): 263. http://dx.doi.org/10.1071/aj98016.
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This paper presents geochemical data—gas chromatography, saturated and aromatic biomarkers, carbon isotopes of bulk fractions and individual n-alkanes—for oils and potential source rocks in the Cooper and Eromanga basins, which show clear evidence for different source-reservoir couplets. The main couplets involve Cooper Basin source and reservoir and Cooper Basin source and Eromanga Basin reservoir. A subordinate couplet involving Eromanga Basin source and Eromanga Basin reservoir is also identified, together with minor inputs from pre-Permian source rocks to reservoirs of the Cooper and Eromanga basins.The source–reservoir relationships are well expressed in the carbon isotopic composition of individual n-alkanes. These data reflect primary controls of source and maturity and are relatively insensitive to secondary alteration through migration fractionation and water washing, processes that have affected the molecular geochemistry of the majority of oils. Accordingly, the principal Gondwanan Petroleum Supersystem originating from a Permian source of the Cooper Basin has been further subdivided into two petroleum systems associated with Lower Permian Patchawarra Formation and Upper Permian Toolachee Formation sources respectively. Both sources are characterised by n-alkane isotope profiles that become progressively lighter with increasing carbon number—negative n-alkane isotope gradient. The Patchawarra source is isotopically lighter than the Toolachee source. Reservoir placement of oil in either the Toolachee or Patchawarra formations is, in general, a good guide to its source and perhaps an indirect measure of seal effectiveness. The subordinate Murta Petroleum Supersystem of the Eromanga Basin is subdivided into the Birkhead Petroleum System and Murta Petroleum System to reflect individual contributions from Birkhead Formation and Murta Formation sources respectively. Both systems are characterised by n-alkane carbon isotope profiles with low to no gradient. The minor Larapintine Petroleum Supersystem has been tentatively identified as involving pre-Permian source rocks in the far eastern YVarburton Basin and western margin of the Warrabin Trough in Queensland.Eromanga source inputs to oil accumulations in the Eromanga Basin can be readily recognised from saturated and aromatic biomarker assemblages. However, biomarkers appear to over-emphasise local Eromanga sources. Hence, we have preferred the semi-quantitative assessment of relative Cooper and Eromanga inputs that can be made using n-alkane isotope data and this appears to be robust provided that Eromanga source input is greater than 25% in oils of mixed origin. Enhanced contributions from Birkhead sources are concentrated in areas of thick and mature Birkhead source rocks in the northeastern Patchawarra Trough. Pre-Permian inputs are readily recognised by n-alkanes more depleted in I3C compared with late Palaeozoic and Mesozoic sources.Long range migration (>50 km) from Permian sources has been established for oil accumulations in the Eromanga Basin. This, together with contributions from local Eromanga sources, highlights petroleum pro- spectivity beyond the Permian edge of the Cooper Basin. Deeper, pre-Permian sources must also be considered in any petroleum system evaluation of the Cooper and Eromanga basins.
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Richards, Brenton, and Alexander Côté. "Exploiting the Cooper Basin: conventional lessons and appropriate analogues to guide an unconventional future." APPEA Journal 58, no. 1 (2018): 339. http://dx.doi.org/10.1071/aj17038.
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Over the past decade, there has been a paradigm shift in the exploitation strategy in North American tight gas plays from vertical to horizontal wells. This shift has yet to occur in Australia. The Cooper Basin has vast amounts of contingent and prospective tight gas resources that have yet to be unlocked commercially. These resources continue to be developed primarily with hydraulic fracture stimulated vertical wells. Operators have yet to challenge the status quo and test the Cooper Basin tight gas potential with a drilled, completed and tested horizontal well. There are many advantages to horizontal well developments, from the ability to target a specific high graded reservoir unit to increased capital efficiency. Operators need to break away from convention and take a new approach to Cooper Basin tight gas exploration and development in the quest to demonstrate commerciality. A review of the inherent challenges in Cooper Basin gas field developments and the current exploitation strategies employed in analogous tight gas plays have been integrated to produce a pragmatic workflow to identify potential reservoir units that would benefit from a change in development strategy.
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Röth, Joschka, and Ralf Littke. "Down under and under Cover—The Tectonic and Thermal History of the Cooper and Central Eromanga Basins (Central Eastern Australia)." Geosciences 12, no. 3 (March 2, 2022): 117. http://dx.doi.org/10.3390/geosciences12030117.
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The Cooper subregion within the central Eromanga Basin is the Swiss army knife among Australia’s sedimentary basins. In addition to important oil and gas resources, it hosts abundant coal bed methane, important groundwater resources, features suitable conditions for enhanced geothermal systems, and is a potential site for carbon capture and storage. However, after seven decades of exploration, various uncertainties remain concerning its tectonic and thermal evolution. In this study, the public-domain 3D model of the Cooper and Eromanga stacked sedimentary basins was modified by integrating the latest structural and stratigraphic data, then used to perform numerical basin modelling and subsidence history analysis for a better comprehension of their complex geologic history. Calibrated 1D/3D numerical models provide the grounds for heat flow, temperature, thermal maturity, and sediment thickness maps. According to calibrated vitrinite reflectance profiles, a major hydrothermal/magmatic event at about 100 Ma with associated basal heat flow up to 150 mW/m2 caused source rock maturation and petroleum generation and probably overprinted most of the previous hydrothermal events in the study area. This event correlates with sedimentation rates up to 200 m/Ma and was apparently accompanied by extensive crustal shear. Structural style and depocentre migration analysis suggest that the Carboniferous–Triassic Cooper Basin initially has been a lazy-s shaped triplex pull-apart basin controlled by the Cooper Basin Master Fault before being inverted into a piggy-back basin and then blanketed by the Jurassic–Cretaceous Eromanga Basin. The interpreted Central Eromanga Shear Zone governed the tectonic evolution from the Triassic until today. It repeatedly induced NNW-SSE directed deformation along the western edge of the Thomson Orogen and is characterized by present-day seismicity and distinct neotectonic features. We hypothesize that throughout the basin evolution, alternating tectonic stress caused frequent thermal weakening of the crust and facilitated the establishment of the Cooper Hot Spot, which recently increased again its activity below the Nappamerri Trough.
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Lockhart, D. A., E. Riel, M. Sanders, A. Walsh, G. T. Cooper, and M. Allder. "Play-based exploration in the southern Cooper Basin: a systematic approach to exploration in a mature basin." APPEA Journal 58, no. 2 (2018): 825. http://dx.doi.org/10.1071/aj17138.
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Exploration within a mature basin poses many challenges, not least how to best utilise resources and time to maximise success and reduce cost. Play-based exploration (PBE) provides a team-based approach to combine key aspects of the petroleum system into an integrated and wholistic view of basin prospectivity. While the PBE methodology is well established, it is not often applied to its full extent on a basin scale. After a period of declining exploration success in parts of the South Australia Cooper-Eromanga Basin, this study was undertaken by a dedicated regional geoscience team with the aim of rebuilding an understanding of the basin, based on first principles and stripping away exploration paradigms. The study area comprises an acreage position in the South Australian and Queensland Cooper-Eromanga Basins covering 70 000 km2 in which Senex Energy has 14 oil fields, has drilled more than 80 exploration wells and has acquired 2D and 3D seismic material. A plethora of proven and emerging plays exist within the acreage ranging from high productivity light sweet oil (Birkhead and Namur Reservoirs) to tight oil (Murta Formation), conventional gas (Toolachee/Epsilon and Patchawarra Formation), tight gas (Patchawarra Formation) and the emerging deep coal play (Toolachee and Patchawarra Coals). Play-based exploration methodologies incorporating the integration of seismic data, log and palynological data, structural analysis, geochemistry, 3D basin modelling, consistent well failure analysis and gross depositional environment maps have allowed the systematic creation of common risk segment maps at all play levels. This information is now actively utilised for permit management, business development, work program creation and portfolio management. This paper will present an example of the work focussing on the southern section of the South Australian Cooper-Eromanga Basin.
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Khaksar, A. "CALIBRATING CORE, LOG AND SEISMIC DATA TO ASSESS EFFECTIVE STRESS AND HYDROCARBON SATURATION, COOPER BASIN, SOUTH AUSTRALIA." APPEA Journal 40, no. 1 (2000): 314. http://dx.doi.org/10.1071/aj99017.
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Laboratory measurements of acoustic properties of representative rock samples, simulating in-situ effective stress and fluid saturation, provide useful guides for calibrating and interpreting seismic and sonic log data. This paper addresses some of the major implications arising from a petro-acoustic study for the evaluation of reservoir depletion of Cooper Basin gas reservoirs using logs and seismic. Measurement of P- and S-wave velocities on cores under varying pressure conditions reveals that the stress dependency of Cooper Basin rocks is very large, while core porosity remains effectively unchanged.The saturation heterogeneity at pore-scale, which is shown in capillary pressure data, controls the velocity- saturation in partially water-saturated samples. The steady decrease of P-wave velocity as saturation decreases from the high saturation range to near irreducible conditions suggests a simultaneous drainage of water from pores with a variety of high to moderate aspect ratios, while microcracks (low aspect ratio pores) retain water. Closure and degree of saturation of the low aspect ratio pores control the velocity-effective stress and velocity-saturation relationships at low saturation and stress conditions.The velocity dispersion due to frequency difference between ultrasonic laboratory measurements on cores and theoretical low (seismic) frequency is about 1%, and thus laboratory-measured velocities are comparable with sonic log and seismic data in the Cooper Basin. The potential of the velocity ratio (Vp/Vs) for detection of fluid type and the saturation status at in-situ reservoir effective stress, and prediction of Vs from Vp, are demonstrated for the Cooper Basin rocks. Acoustic measurements on cores, wireline data and seismic modelling are used to predict the expected change in seismic response as the reservoir depletes. Synthetic seismic profiles indicate that the zero-offset reflectivity of a shale to reservoir interface decreases by 28% for a 30 MPa pressure depletion in a typical gas expansion drive reservoir. Such changes should be easily measurable between repeated surveys, suggesting that time-lapse seismic for the monitoring of in-situ effective stress and saturation may have application in Cooper Basin reservoirs. Although these findings refer specifically to the Cooper Basin, the methods used and results of this study may be applicable elsewhere.
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Ruth, Peter van, Richard Hillis, Richard Swarbrick, Peter Tingate, and Scott Midren. "The Origin of Overpressure in the Cooper Basin, Australia." ASEG Extended Abstracts 2003, no. 2 (August 2003): 1–5. http://dx.doi.org/10.1071/aseg2003ab174.
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McKenna, Jason R., and Graeme Beardsmore. "Geothermal Potential associated with Hydrocarbon Production, Cooper Basin, Australia." ASEG Extended Abstracts 2006, no. 1 (December 2006): 1. http://dx.doi.org/10.1071/aseg2006ab108.
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Rezaee, M. R., and N. M. Lemon. "Estimation of Effective Porosity, Tirrawarra Sandstone, Cooper Basin, Australia." Exploration Geophysics 28, no. 1-2 (March 1997): 114–18. http://dx.doi.org/10.1071/eg997114.
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Martin, N. W. "THE COOPER BASIN NATIVE TITLE AGREEMENTS—AN EXPLORER’S PERSPECTIVE." APPEA Journal 42, no. 1 (2002): 711. http://dx.doi.org/10.1071/aj01047.
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On 22 October 2001 in Adelaide, the successful bidders for the 1998 First Round Cooper Basin Acreage Release, the South Australian Government, and various native title claimant groups completed the signing of historic and long awaited native title agreements. A few days later, the Petroleum Exploration Licences (PEL) were issued in respect of the blocks covered by those agreements, and so commenced a new era of oil and gas exploration in South Australia.This paper examines the process that led to the finalisation of negotiations and the signing of the agreements, from the perspective of one of the exploration companies that participated in the negotiations.
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Wyborn, D., L. de Graaf, S. Hann, and B. Nicholson. "PROGRESS IN GEOTHERMAL ENERGY DEVELOPMENT, COOPER BASIN, SOUTH AUSTRALIA." APPEA Journal 45, no. 1 (2005): 175. http://dx.doi.org/10.1071/aj04015.
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Geodynamics Limited is nearing the completion of its ‘proof of concept’ hot fractured rock (HFR) program to extract superheated hot water for electricity generation from granite buried beneath the Cooper Basin. Difficult drilling conditions were discovered in the target granite when the Habanero–1 well penetrated permeable sub-horizontal fractures at more than 4,000 m depth. The well was completed at 4,421 m with overpressures in the fractures around this depth exceeding pressures projected from a hydrostatic gradient by more than 5,000 psi. The static rock temperature at the bottom of the well is about 250°C.The overpressures assisted in the development of the world’s largest underground heat exchanger, a volume of rock more than 0.7 km3 defined by more than 11,700 microseismic events located on-site during the injection of 23 ML of fresh water into the granite fracture network. The horizontal heat exchanger is more than 2 km north–south, more than 1 km east–west and more than 300 m thick. During its development there was no evidence of direct upwards growth towards the sedimentary cover, which is at about 3,700 m, though a small number of events were observed above the main cloud of events. From production logging surveys, a major fracture at a depth of 4,254 m is interpreted to have taken most of the flow during the injection.The second well (Habanero–2) was located 500 m southwest of the first. Before intersecting a major fracture, interpreted to be an extension of the dominant fracture in Habanero–1, it was drilled to a depth of 4,325 m. At this depth, total drilling circulation losses were encountered which were only partially overcome with the pumping of calcium carbonate lost circulation material. During the operation the lower 245 m of the drill stem was irretrievably lost, and the well was subsequently sidetracked to a total depth of 4,358 m, just below the main fracture.Flow and circulation testing between the two wells in early 2005 is designed to demonstrate the economic potential of the far-field geothermal system and the heat exchange volume between the two wells.
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G.H.Taylor, G. H. Taylor, Susie Y. Liu, and Michelle Smyth. "NEW LIGHT ON THE ORIGIN OF COOPER BASIN OIL." APPEA Journal 28, no. 1 (1988): 303. http://dx.doi.org/10.1071/aj87023.
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The Cooper Basin in central Australia is a major producer of gas and oil. It is generally accepted that the organic matter in the Permian terrestrial sediments of the Basin was the source of the oil and gas. However, both the coals and the dispersed organic matter (DOM) are rich in inertinite and both inertinite itself and inertinite-rich organic matter have been widely discounted as a possible source for oil.Recent co-ordinated transmission electron microscope and light microscope work on the inertiniterich coals of the Cooper Basin has shown that up to several per cent of some coal samples are composed of microscopic and sub-microscopic alginite. This includes material that had previously been identified with the light microscope alone as degraded sporinite, liptodetrinite or resinite, as well as algal-derived matter, which is too fine to observe with light microscopy. Much of this material of algal origin was selectively degraded at about the time of its deposition, and this degradation appears likely to have had the effect of further enhancing its potential to yield hydrocarbons. Thus, such material should be ranked among the richest potential sources of hydrocarbons when appropriate diagenetic conditions have been attained. Since inertinite and this kind of alginite occur in particularly close association, the presence of inertinite-rich coals and DOM within potential source rocks should be regarded as a highly favourable rather than an unfavourable, indication (as in the past).The quantity of alginite in the very large volumes of inertinite-rich coal in the Basin is more than adequate to account for the oil accumulations. In the Cooper Basin the coals, rather than the DOM, had the better potential for oil generation.
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Taylor, S., G. Solomon, N. Tupper, J. Evanochko, G. Horton, R. Waldeck, and S. Phillips. "FLANK PLAYS AND FAULTED BASEMENT: NEW DIRECTIONS FOR THE COOPER BASIN." APPEA Journal 31, no. 1 (1991): 56. http://dx.doi.org/10.1071/aj90006.
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The Moomba and Big Lake Gas Field area has been actively explored for 25 years. However, recent drilling and field studies have identified new reservoir objectives for appraisal of established fields and for exploration in wildcat areas. Cooper Basin reserves have been increased and further additions are likely. Integration of drilling, production and pressure data for the Moomba and Big Lake Fields has resulted in the discovery of a structural-stratigraphic trap on the south-west flank of the Moomba Dome. Moomba-65 flowed gas at 9.8 MMCFD (0.27 Mm3/d) from deltaic sandstone of the Epsilon Formation (Early Permian). Similar plays are likely to be found on the flanks of other Cooper Basin fields and will become increasingly important as opportunities for conventional crestal tests of anticlines diminish.Exploration to the south-west of the Moomba Field has established the first significant gas flows from rocks beneath the conventional reservoirs of the Cooper Basin. Lycosa-1 drilled a faulted anticline and achieved a maximum gas flow of 5.0 MMCFD (0.14 Mm3/d) from fractured metasiltstone of the Dullingari Group (Ordovician). Moo- lalla-1 drilled a low-side fault terrace and flowed gas at 9.6 MMCFD (0.27 Mm3/d) from 'protoquartzite' tentatively assigned to the Dullingari Group. Consequently, structures where 'basement' reservoirs are faulted against mature Patchawarra Formation source rocks are attractive exploration targets.Petrological studies have identified 'glauconitic illite' in the Cooper Basin sequence suggesting hitherto unrecognised marine conditions. A reassessment of the source and reservoir potential of the region will be necessary if the presence of marine environments is substantiated by further studies.
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Pokalai, Kunakorn, Yang Fei, Maqsood Ahmad, Manouchehr Haghighi, and Mary Gonzalez. "Design and optimisation of multi-stage hydraulic fracturing in a horizontal well in a shale gas reservoir in the Cooper Basin, South Australia." APPEA Journal 55, no. 1 (2015): 1. http://dx.doi.org/10.1071/aj14001.
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Multi-stage hydraulic fracturing in horizontal wells is a well-known technology and is a key mechanism for gas recovery from extremely low permeable shale gas reservoirs. Since Australia’s Cooper Basin has a more complex stress regime and higher temperatures when compared to US shale gas formations, the design and optimisation of this technology in the Cooper Basin has not been explored to the authors’ knowledge. The Murteree and Roseneath shale formations in the Cooper Basin are 8,500 ft in depth and have been targets for shale gas production by different oil and gas operators. Deeper zones are difficult to fracture, as fracture gradients are often above 1 psi/ft. In this study, 1D vertical mechanical earth modelling using petrophysical log data was developed. Then, the stress profile was tuned and validated using the minimum horizontal stress from a mini-frac test taken along a vertical well. A 3D hydraulic fracture simulation in a vertical well as developed as a pilot to select the best locations for horizontal drilling. The selection criteria for the best location included the stress regime, gas flow rate and fracture geometry. Then a multi-stage fracture treatment in a horizontal well was designed. A large number of cases were simulated based on different well lengths, stage spacing and the number of stages. The productivity index was selected as the objective function for the optimisation process. The best case finally was selected as the optimum multi-stage hydraulic fracturing in a horizontal well in the Cooper Basin.
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Alexander, Elinor, and Alan Sansome. "Shaping the Cooper Basin's 21st century renaissance." APPEA Journal 52, no. 2 (2012): 690. http://dx.doi.org/10.1071/aj11104.
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The Department of Manufacturing, Innovation, Trade, Resources and Energy (DMITRE) SA has been successfully using competitive acreage releases to manage highly prospective Cooper Basin acreage since 1998. The expiry of long-term exploration licenses enabled the most significant structured release of onshore Australian acreage in the industry’s history—it has generated: 32 petroleum exploration licences (PELs) from ~70,000 km2 acreage; $432 million in guaranteed work program bids; 70 new field discoveries; $107.6 million royalties and $1.4 billion sales;and, increased gas supply-side competition. Cooper acreage turnover has also changed the makeup of Australia’s onshore exploration industry from numerous company-making discoveries. Since 1998, 10 acreage releases have been staged, enabled by the Petroleum Act 2000 (now the Petroleum and Geothermal Energy Act 2000), conjunctive agreements with Native Title claimants, access to multiple-use Innamincka and Strzelecki Regional Reserves, and transparent application and bid assessment processes. Despite delays, most recently due to flooding, all but three of the original PELs are in their second term and relinquished acreage has been incorporated into subsequent releases. All work-program variations have been kept above the second bid score (except one, where the second ranked bidder was consulted and approved the change) preserving bidding system integrity. DMITRE is planning new Cooper Basin acreage releases while contemplating acreage management options for emerging unconventional plays. Industry input to map the best possible future for the SA Cooper Basin continues to be welcomed.
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Baisch, Stefan, Elmar Rothert, Henrik Stang, Robert Vörös, Christopher Koch, and Andrew McMahon. "Continued Geothermal Reservoir Stimulation Experiments in the Cooper Basin (Australia)." Bulletin of the Seismological Society of America 105, no. 1 (January 13, 2015): 198–209. http://dx.doi.org/10.1785/0120140208.
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Poole, Anastasia, Peter van Baaren, John Quigley, Gabriele Busanello, Sharon Tan, Chester Hobbs, and Brendon Mitchell. "“Texas in Australia? Imaging channel sands in the Cooper Basin”." ASEG Extended Abstracts 2013, no. 1 (December 2013): 1–4. http://dx.doi.org/10.1071/aseg2013ab140.
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Gallagher, Kerry. "Thermal Conductivity And Heat Flow In The Southern Cooper Basin." Exploration Geophysics 18, no. 1-2 (March 1, 1987): 62–65. http://dx.doi.org/10.1071/eg987062.
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Fernandez-Ibañez, Fermin, David Castillo, Doone Wyborn, Dean Hindle, and Adrian White. "Temperature-dependent stability of deep wells in the Cooper Basin." APPEA Journal 50, no. 2 (2010): 734. http://dx.doi.org/10.1071/aj09098.
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The Cooper-Eromanga Basin is characterised by high heat flow that has been related to the presence of high radiogenic heat-producing granites. Several wells have been drilled in the area to exploit the heat from the fractured granitic rocks of the basement. Drilling through the hot formations in the Cooper Basin (max. temperature ca. 250 °C) with relatively cool drilling fluids induces an almost instantaneous cooling of the wellbore wallrock. Cooling of the hole (the usual case) increases the tensile stresses (and decreases the compressive stresses) at the wellbore wall. The magnitude of the thermal stresses is also dependent on the silica content of the formation. Modelling of the in situ stress tensor and mechanical properties of the wellbore rocks has revealed the time-dependent effect that the borehole collapse pressure has on the stability of the wells. Narrow breakouts form at the time of drilling. Afterwards, the temperature difference (ΔT) decays with time, and as the hole warms up compressive stresses increase and breakouts become enhanced. Therefore, if a high ΔT and a short well exposure time are achieved, it would be possible to inhibit breakout development, drill with a lower mud weight (eventually underbalanced), and, thus, minimise the risk of formation damage.
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Kulikowski, D., K. Amrouch, and D. Cooke. "Geomechanical modelling of fault reactivation in the Cooper Basin, Australia." Australian Journal of Earth Sciences 63, no. 3 (April 2, 2016): 295–314. http://dx.doi.org/10.1080/08120099.2016.1212925.
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Hill, A. J., and A. J. Mauger. "HyLogging unconventional petroleum core from the Cooper Basin, South Australia." Australian Journal of Earth Sciences 63, no. 8 (November 16, 2016): 1087–97. http://dx.doi.org/10.1080/08120099.2016.1261369.
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Williams, B. P. J., E. K. Wild, and R. J. Suttill. "Late Palaeozoic cold-climate aeolianites, southern Cooper Basin, South Australia." Geological Society, London, Special Publications 35, no. 1 (1987): 233–49. http://dx.doi.org/10.1144/gsl.sp.1987.035.01.16.
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Alganaeva, Elena, and Greg Smith. "Formation of Very Thick Permian Coal Seams, Cooper Basin, Australia." ASEG Extended Abstracts 2019, no. 1 (November 11, 2019): 1–4. http://dx.doi.org/10.1080/22020586.2019.12073215.
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Trembath, Carrie, Lindsay Elliott, and Mark Pitkin. "The Nappamerri Trough, Cooper Basin unconventional plays: proving a hypothesis." APPEA Journal 52, no. 2 (2012): 662. http://dx.doi.org/10.1071/aj11076.
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Beach Energy has started exploring unconventional gas in the Nappamerri Trough, the central trough within the Cooper Basin, where the Permian section has long been regarded as the primary source for most of the conventional hydrocarbons found within the basin. This extended abstract discusses the data used to identify the unconventional play and the exploration program carried out to date. Mud weights, drill stem test (DST) pressures and log data from early exploration wells identified the Permian formations as overpressured. This with geochemical and mineralogy analyses indicated that the Roseneath and Murteree Shales had potential similar to successful shale gas plays being developed in the USA. The quartz and siderite content within both shale sections indicated sufficient brittleness for successful fracture stimulation. In addition, the Nappamerri Trough Permian section showed low permeabilities, which, when combined with overpressure, suggested a basin-centred style play within the Epsilon and Patchawarra sandstones and possibly the Toolachee Formation sandstones. During 2010–11, Beach drilled two exploration wells sited outside structural closure to test both the shale gas and basin centred gas system. Both wells have now been fracture stimulated, with very encouraging gas flows from the Roseneath to Patchawarra section. The latest geological data confirms the pre-drill potential for both gas flow from the shales and the presence and production of gas from sandstones outside structural closure, resulting in a significant shale and tight gas resource booking. Ongoing exploration and development will target a potential 300 Tcf gas in place in PEL 218.
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Menpes, Sandra, and Tony Hill. "Emerging continuous gas plays in the Cooper Basin, South Australia." APPEA Journal 52, no. 2 (2012): 671. http://dx.doi.org/10.1071/aj11085.
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Recent off-structure drilling in the Nappamerri Trough has confirmed the presence of gas saturation through most of the Permian succession, including the Roseneath and Murteree shales. Basin-centred gas, shale gas and deep CSG plays in the Cooper Basin are now the focus of an escalating drilling and evaluation campaign. The Permian succession in the Nappamerri Trough is up to 1,000 m thick, comprising very thermally mature, gas-prone source rocks with interbedded sands—ideal for the creation of a basin-centred gas accumulation. Excluding the Murteree and Roseneath shales, the succession comprises up to 45% carbonaceous and silty shales and thin coals deposited in flood plain, lacustrine and coal swamp environments. The Early Permian Murteree and Roseneath shales are thick, generally flat lying, and laterally extensive, comprising siltstones and mudstones deposited in large and relatively deep freshwater lakes. Total organic carbon values average 3.9% in the Roseneath Shale and 2.4% in the Murteree Shale. The shales lie in the wet gas window (0.95–1.7% Ro) or dry gas window (>1.7% Ro) over much of the Cooper Basin. Thick Permian coals in the deepest parts of the Patchawarra Trough and over the Moomba high on the margin of the Nappamerri Trough are targets for deep CSG. Gas desorption analysis of a thick Patchawarra coal seam returned excellent total raw gas results averaging 21.2 scc/g (680 scf/ton) across 10 m. Scanning electron microscopy has shown that the coals contain significant microporosity.
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Seggie, R. J. "RESERVOIR CHARACTERISATION OF THE MOORARI/WOOLKINA FIELD COMPLEX, COOPER BASIN." APPEA Journal 37, no. 1 (1997): 70. http://dx.doi.org/10.1071/aj96004.
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The Tirrawarra Sandstone oil accumulation at the Moorari/Woolkina Field complex in the Cooper Basin, Central Australia has been under miscible gas flood EOR since 1984. A facies-based reservoir characterisation study of the field was undertaken to help explain unpredicted field performance and to provide a reliable model on which to base any future field development and necessary engineering studies prior to blow down.The reservoir is dominated by the interaction of fluvial braid-plain and glacio-lacustrine shoreface processes in a braid-delta setting. It comprises five basic facies from which eleven sub-facies are identified, eight containing oil bearing reservoir. An extensive field wide lacustrine mudstone acts as a vertical barrier and divides the reservoir into two gross sand units. The individual sub-facies were petrographically and petrophysically characterised and mapped in detail to provide a model of the field architecture, within which the residency of the original and remaining oil-in-place was determined.A substantial increase in OOIP explained the better than predicted performance from the EOR pattern and highlighted the field flanks for assessment for incremental development. This was confirmed by the engineering data review which also revealed that the poor structurally low wells were affected by relative permeability effects. As a result of this study, plans for incremental field development are in progress with the goal of increasing reserves and production.
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Rees, Nigel, Simon Carter, Graham Heinson, and Lars Krieger. "Monitoring shale gas resources in the Cooper Basin using magnetotellurics." GEOPHYSICS 81, no. 6 (November 2016): A13—A16. http://dx.doi.org/10.1190/geo2016-0187.1.
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The magnetotelluric (MT) method is introduced as a geophysical tool to monitor hydraulic fracturing of shale gas reservoirs and to help constrain how injected fluids propagate. The MT method measures the electrical resistivity of earth, which is altered by the injection of fracturing fluids. The degree to which these changes are measurable at the surface is determined by several factors, such as the conductivity and quantity of the fluid injected, the depth of the target interval, the existing pore fluid salinity, and a range of formation properties, such as porosity and permeability. From an MT monitoring survey of a shale gas hydraulic fracture in the Cooper Basin, South Australia, we have found temporal and spatial changes in MT responses above measurement error. Smooth inversions are used to compare the resistivity structure before and during hydraulic fracturing, with results showing increases in bulk conductivity of 20%–40% at a depth range coinciding with the horizontal fracture. Comparisons with microseismic data lead to the conclusion that these increases in bulk conductivity are caused by a combination of the injected fluid permeability and an increase in wider scale in situ fluid permeability.
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Wiltshire, D. "NATURAL VERSUS ACTIVE REHABILITATION OF SEISMIC LINES INTHE COOPER BASIN." APPEA Journal 40, no. 1 (2000): 709. http://dx.doi.org/10.1071/aj99049.
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Extensive investigations undertaken in the Cooper Basin during the 1980s reveal that seismic lines prepared in dunefield and floodplain land systems rehabilitated naturally within a reasonable timeframe. It also appeared, however, that lines prepared in the dissected residual and gibber plains land systems would persist virtually indefinitely without active intervention. The principal issues were identified as being the ongoing aesthetic impacts of rocky windrows, ongoing expansion of erosion gullies and scars on hillsides and escarpments.Subsequently, an extensive seismic line restoration program was undertaken in gibber land units, in which graders were used to respread windrows over seismic lines, to install erosion control structures at the head of active gullies and to batter the edges of small erosion gullies. In general, the program was highly successful in reducing the visual impact of seismic lines and speeding the rehabilitation of small gullies.Active rehabilitation of large erosion gullies and scarred escarpments was not attempted, as it was considered that the process would be very expensive and would result in only marginal aesthetic improvements. Subsequent investigations have revealed that the lateral erosion and slumping of erosion gullies will, within a reasonable timeframe, result in the gullies resembling natural drainage features as revegetation occurs and the linear connection with the restored seismic line on the adjoining footslopes disappears.
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Ambrose, G., M. Scardigno, and A. J. Hill. "PETROLEUM GEOLOGY OF MIDDLE–LATE TRIASSIC AND EARLY JURASSIC SEQUENCES IN THE SIMPSON BASIN AND NORTHERN EROMANGA BASIN OF CENTRAL AUSTRALIA." APPEA Journal 47, no. 1 (2007): 127. http://dx.doi.org/10.1071/aj06007.
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Prospective Middle–Late Triassic and Early Jurassic petroleum systems are widespread in central Australia where they have only been sparsely explored. These systems are important targets in the Simpson/Eromanga basins (Poolowanna Trough and surrounds), but the petroleum systems also extend into the northern and eastern Cooper Basin.Regional deposition of Early–Middle Triassic red-beds, which provide regional seal to the Permian petroleum system, are variously named the Walkandi Formation in the Simpson Basin, and the Arrabury Formation in the northern and eastern Cooper Basin. A pervasive, transgressive lacustrine sequence (Middle–Late Triassic Peera Peera Formation) disconformably overlies the red-beds and can be correlated over a distance of 500 km from the Poolowanna Trough into western Queensland, thus providing the key to unravelling Triassic stratigraphic architecture in the region. The equivalent sequence in the northern Cooper Basin is the Tinchoo Formation. These correlations allow considerable simplification of Triassic stratigraphy in this region, and demonstrate the wide lateral extent of lacustrine source rocks that also provide regional seal. Sheet-like, fluvial-alluvial sands at the base of the Peera Peera/Tinchoo sequence are prime reservoir targets and have produced oil at James–1, with widespread hydrocarbon shows occurring elsewhere including Poolowanna–1, Colson–1, Walkandi–1, Potiron–1 and Mackillop–1.The Early Jurassic Poolowanna Formation disconformably overlies the Peera Peera Formation and can be subdivided into two transgressive, fluvial-lacustrine cycles, which formed on a regional scale in response to distal sea level oscillations. Early Jurassic stratigraphic architecture in the Poolowanna Trough is defined by a lacustrine shale capping the basal transgressive cycle (Cycle 1). This shale partitions the Early Jurassic aquifer in some areas and significant hydrocarbon shows and oil recoveries are largely restricted to sandstones below this seal. Structural closure into the depositional edge of Cycle 1 is an important oil play.The Poolowanna and Peera Peera formations, which have produced minor oil and gas/condensate on test respectively in Poolowanna–1, include lacustrine source rocks with distinct coal maceral compositions. Significantly, the oil-bearing Early Jurassic sequence in Cuttapirrie–1 in the Cooper Basin correlates directly with the Cycle–1 oil pool in Poolowanna–1. Basin modelling in the latter indicates hydrocarbon expulsion occurred in the late Cretaceous (90–100 Ma) with migration into a subtle Jurassic age closure. Robust Miocene structural reactivation breached the trap leaving only minor remnants of water-washed oil. Other large Miocene structures, bound by reverse faults and some reflecting major inversion, have failed to encounter commercial hydrocarbons. Future exploration should target subtle Triassic to Jurassic–Early Cretaceous age structural and combination stratigraphic traps largely free of younger fault dislocation.
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Hillis, R. R., J. G. G. Morton, D. S. Warner, and R. K. Penney. "DEEP BASIN GAS: A NEW EXPLORATION PARADIGM IN THE NAPPAMERRI TROUGH, COOPER BASIN, SOUTH AUSTRALIA." APPEA Journal 41, no. 1 (2001): 185. http://dx.doi.org/10.1071/aj00009.
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Deep basin hydrocarbon accumulations have been widely recognised in North America and include the giant fields of Elmworth and Hoadley in the Western Canadian Basin. Deep basin accumulations are unconventional, being located downdip of water-saturated rocks, with no obvious impermeable barrier separating them. Gas accumulations in the Nappamerri Trough, Cooper Basin, exhibit several characteristics consistent with North American deep basin accumulations. Log evaluation suggests thick gas columns and tests have recovered only gas and no water. The resistivity of the entire rock section exceeds 20 Ωm over large intervals, and, as in known deep basin accumulations, the entire rock section may contain gas. Gas in the Nappamerri Trough is located within overpressured compartments which witness the hydraulic isolation necessary for gas saturation outside conventional closure. Furthermore, the Nappamerri Trough, like known deep basin accumulations, has extensive, coal-rich source rocks capable of generating enormous hydrocarbon volumes. The above evidence for a deep basin-type gas accumulation in the Nappamerri Trough is necessarily circumstantial, and the existence of a deep gas accumulation can only be proven unequivocally by drilling wells outside conventional closure.Exploration for deep basin-type accumulations should focus on depositional-structural-diagenetic sweet spots (DSDS), irrespective of conventional closure. This is of particular significance for a potential Nappamerri Trough deep basin accumulation because depositional models suggest that the best net/gross may be in structural lows, inherited from syndepositional lows, that host stacked channel sands within channel belt systems. Limiting exploration to conventionally-trapped gas may preclude intersection with such sweet spots.
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Roberts, D. C., P. G. Carroll, and J. Sayers. "THE KALLADEINA FORMATION – A WARBURTON BASIN CAMBRIAN CARBONATE PLAY." APPEA Journal 30, no. 1 (1990): 166. http://dx.doi.org/10.1071/aj89010.
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The Warburton Basin is currently considered economic basement to the gas-oil productive Cooper Basin and the oil productive Eromanga Basin. Only 10 wells have penetrated more than 100 m of the Kalladeina Formation which is identified as the most prospective section within the Warburton Basin. The Kalladeina Formation consists of more than 1600 m of carbonate shelf sediments deposited during the early Cambrian to early Ordovician in a basin consisting of half grabens on the continental side of an active margin.Several intra-Kalladeina Formation seismic events in a 500 km2 region to the west of the Gidgealpa oil and gas field have been tied to wells with palaeontological control. Structure and isopach mapping illustrates large scale thrusts, wrench fault zones and subcrop edges for the Kalladeina Formation. Maps of unconformities and of formations above the Warburton Basin define source, seal and trap relationships.Good carbonate reservoirs have been identified in the Kalladeina Formation but the source potential of this succession appears to be restricted. The overlying Cooper Basin source rocks may have charged the underlying carbonates and this represents one of three play types identified in the area.All Warburton Basin plays are very high risk but potential reserves are also large.
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Moriarty, Hayden, Jennifer Clifford, James Donley, and Lewis Maxwell. "Unlocking material gas resources – Moomba South case study." APPEA Journal 60, no. 2 (2020): 736. http://dx.doi.org/10.1071/aj19222.
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In the last two years, Santos has identified and unlocked a significant contingent resource in the Cooper Basin, onshore Australia. Commercialisation of these resources has been enabled through the application of phased appraisal programs, combined with Santos’ disciplined low-cost operating model. The implementation of a disciplined low-cost operating model as part of the current Santos strategy has resulted in unprecedented cost reductions in the Cooper Basin. Sub-economic contingent resources across many fields have become primary targets for appraisal and development for conversion to economic reserves. One of Santos’ largest contingent resources lies in the deep tight rocks of the Moomba Field.
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Carr, Lidena, Russell Korsch, and Tehani Palu. "Australia's onshore basin inventory: volume I." APPEA Journal 56, no. 2 (2016): 591. http://dx.doi.org/10.1071/aj15097.
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Following the publication of Geoscience Australia Record 2014/09: Petroleum geology inventory of Australia’s offshore frontier basins by Totterdell et al (2014), the onshore petroleum section of Geoscience Australia embarked on a similar project for the onshore Australian basins. Volume I of this publication series contains inventories of the McArthur, South Nicholson, Georgina, Amadeus, Warburton, Wiso, Galilee, and Cooper basins. A comprehensive review of the geology, petroleum systems, exploration status, and data coverage for these eight Australian onshore basins was conducted, based on the results of Geoscience Australia’s precompetitive data programs, industry exploration results, and the geoscience literature. A petroleum prospectivity ranking was assigned to each basin, based on evidence for the existence of an active petroleum system. The availability of data and level of knowledge in each area was reflected in a confidence rating for that ranking. This extended abstract summarises the rankings assigned to each of these eight basins, and describes the type of information available for each of these basins in the publically available report by Carr et al (2016), available on the Geoscience Australia website. The record allocated a high prospectivity rating for the Amadeus and Cooper basins, a moderate rating for the Galilee, McArthur and Georgina basins, and a low rating for the South Nicholson, Warburton and Wiso basins. The record lists how best to access data for each basin, provides an assessment of issues and unanswered questions, and recommends future work directions to lessen the risk of these basins in terms of their petroleum prospectivity. Work is in progress to compile inventories on the next series of onshore basins.