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1
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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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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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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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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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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Deighton, I., J. J. Draper, A. J. Hill, and C. J. Boreham. "A HYDROCARBON GENERATION MODEL FOR THE COOPER AND EROMANGA BASINS." APPEA Journal 43, no. 1 (2003): 433. http://dx.doi.org/10.1071/aj02023.
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The aim of the National Geoscience Mapping Accord Cooper-Eromanga Basins Project was to develop a quantitative petroleum generation model for the Cooper and Eromanga Basins by delineating basin fill, thermal history and generation potential of key stratigraphic intervals. Bio- and lithostratigraphic frameworks were developed that were uniform across state boundaries. Similarly cross-border seismic horizon maps were prepared for the C horizon (top Cadna-owie Formation), P horizon (top Patchawarra Formation) and Z horizon (base Eromanga/Cooper Basins). Derivative maps, such as isopach maps, were prepared from the seismic horizon maps.Burial geohistory plots were constructed using standard decompaction techniques, a fluctuating sea level and palaeo-waterdepths. Using terrestrial compaction and a palaeo-elevation for the Winton Formation, tectonic subsidence during the Winton Formation deposition and erosion is the same as the background Eromanga Basin trend—this differs significantly from previous studies which attributed apparently rapid deposition of the Winton Formation to basement subsidence. A dynamic topography model explains many of the features of basin history during the Cretaceous. Palaeo-temperature modelling showed a high heatflow peak from 90–85 Ma. The origin of this peak is unknown. There is also a peak over the last two–five million years.Expulsion maps were prepared for the source rock units studied. In preparing these maps the following assumptions were made:expulsion is proportional to maturity and source rock richness;maturity is proportional to peak temperature; andpeak temperature is proportional to palaeo-heatflow and palaeo-burial.The geohistory modelling involved 111 control points. The major expulsion is in the mid-Cretaceous with minor amounts in the late Tertiary. Maturity maps were prepared by draping seismic structure over maturity values at control points. Draping of maturity maps over expulsion values at the control points was used to produce expulsion maps. Hydrocarbon generation was calculated using a composite kerogen kinetic model. Volumes generated are theoretically large, up to 120 BBL m2 of kitchen area at Tirrawarra North. Maps were prepared for the Patchawarra and Toolachee Formations in the Cooper Basin and the Birkhead and Poolowanna Formations in the Eromanga Basins. In addition, maps were prepared for Tertiary expulsion. The Permian units represent the dominant source as Jurassic source rocks have only generated in the deepest parts of the Eromanga Basin.
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Schulz-Rojahn, J. P. "CALCITE-CEMENTED ZONES IN THE EROMANGA BASIN: CLUES TO PETROLEUM MIGRATION AND ENTRAPMENT?" APPEA Journal 33, no. 1 (1993): 63. http://dx.doi.org/10.1071/aj92006.
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The occurrence of calcite cementation zones in oil- bearing sequences of the Jurassic-Cretaceous Eromanga Basin is of importance to petroleum exploration. The erratic distribution and thickness of these calcite-cemented intervals is problematic for both prediction of subsurface reservoir quality and structural interpretation of seismic data due to velocity anomalies.Carbon isotope signatures suggest the carbonate cements may form by dissipation of carbon dioxide upward from the Cooper Basin into the calcium-bearing J-aquifers of the Great Artesian Basin of which the Eromanga Basin forms a part. The model is feasible if the pH of the Eromanga Basin aquifer waters is buffered externally, by generation of organic acid anions during kerogen maturation or aluminosilicate reactions.Hydrocarbons are likely to have migrated up-dip along the same conduits as the carbon dioxide. Consequently, delineation of massive calcite-cemented zones in the Eromanga Basin reservoirs using well log and seismic data may aid in the identification of petroleum migration pathways, and sites of hydrocarbon entrapment.
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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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Wecker, H. R. B. "THE EROMANGA BASIN." APPEA Journal 29, no. 1 (1989): 379. http://dx.doi.org/10.1071/aj88032.
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The Eromanga Basin, encompassing an area of approximately 1 million km2 in Central Australia, is a broad intracratonic downwarp containing up to 3000 m of Middle Triassic to Late Cretaceous sediments.Syndepositional tectonic activity within the basin was minimal and the main depocentres largely coincide with those of the preceding Permo- Triassic basins. Several Tertiary structuring phases, particularly in the Early Tertiary, have resulted in uplift and erosion of the Eromanga Basin section along its eastern margin, and the development of broad, northwesterly- to northeasterly- trending anticlines within the basin. In some instances, high angle faults are associated with these features. This structural deformation occurred in an extensional regime and was strongly influenced by the underlying Palaeozoic structural grain.The Eromanga Basin section is composed of a basal, dominantly non- marine, fluvial and lacustrine sequence overlain by shallow marine deposits which are in turn overlain by another fluvial, lacustrine and coal- swamp sequence. The basal sequence is the principal zone of interest to petroleum exploration. It contains the main reservoirs and potential source rocks and hosts all commercial hydrocarbon accumulations found to date. While the bulk of discovered reserves are in structural traps, a significant stratigraphic influence has been noted in a number of commercially significant hydrocarbon accumulations.All major discoveries have been in the central Eromanga Basin region overlying and adjacent to the hydrocarbon- productive, Permo- Triassic Cooper Basin. The mature Permian section is believed to have contributed a significant proportion of the Eromanga- reservoired hydrocarbons. Accordingly, structural timing and migration pathways within the Permian and Middle Triassic- Jurassic sections are important factors for exploration in the central Eromanga Basin region. Elsewhere, in less thermally- mature areas, hydrocarbon generation post- dates Tertiary structuring and thus exploration success will relate primarily to source- rock quality, maturity and drainage factors.Although exploration in the basin has proceeded spasmodically for over 50 years, it has only been in the last decade that significant exploration activity has occurred. Over this recent period, some 450 exploration wells and 140 000 km of seismic acquisition have been completed in the pursuit of Eromanga Basin oil accumulations. This has resulted in the discovery of 227 oil and gas pools totalling an original in- place proved and probable (OOIP) resource of 360 MMSTB oil and 140 BCF gas.Though pool sizes are generally small, up to 5 MMSTB OOIP, the attractiveness of Eromanga exploration lies in the propensity for stacked pools at relatively shallow depths, moderate to high reservoir productivity, and established infrastructure with pipelines to coastal centres. Coupled with improved exploration techniques and increasing knowledge of the basinal geology, these attributes will undoubtedly ensure the Eromanga Basin continues to be a prime onshore area for future petroleum exploration in Australia.
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Craig, Adam. "Exploration and appraisal year in review 2021." APPEA Journal 62, no. 2 (May 13, 2022): S527—S536. http://dx.doi.org/10.1071/aj21222.
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Petroleum exploration and appraisal activity increased in 2021. Exploration spend increased for the year, continuing a positive trend. Onshore exploration and appraisal activity continues to dominate the petroleum exploration scene in Australia. Positive indications of increased work program bids (wells, seismic and spend) are, however, tempered by the downward trend of total exploration acreage (by area) and new acreage awards. In addition to petroleum exploration acreage, greenhouse gas sequestration acreage was released across Australia in 2021. Twenty-nine exploration wells were drilled in the year compared to twenty-five in the previous year. Eight conventional petroleum discoveries were reported, with the Artisan-1 discovery in the Otway Basin being the only offshore discovery. The Lockyer Deep-1 gas discovery in the Northern Perth Basin continues the exploration success of the Permian Kingia and High Cliff Sandstone play. The Cooper–Eromanga Basin continues to yield discoveries with the Odin-1, Rosebay-1, Lowry South, Liger-1 and Chimera-1 discoveries reported for the year. Thirty-one appraisal wells were drilled for the year with significant activity in the Northern Perth Basin, Cooper-Eromanga Basin and Bowen-Surat Basins. Exploration and appraisal drilling also continued in the Beetaloo Sub-basin with the drilling of the Tanumbirini-2H, Tanumbirini-3H and Carpentaria-2/2H wells during the year.
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Tupper, N. P., and D. M. Burckhardt. "USE OF THE METHYLPHENANTHRENE INDEX TO CHARACTERISE EXPULSION OF COOPER AND EROMANGA BASIN OILS." APPEA Journal 30, no. 1 (1990): 373. http://dx.doi.org/10.1071/aj89025.
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The methylphenanthrene index (MPI) molecular maturity parameter is available for over 100 Cooper and Eromanga Basin oils. Oil maturity data define the threshold and range of expulsion maturity for source rocks and can be used to determine oil-source affinity. Mapping of this maturity range for all potential source rocks identifies areas of greatest oil potential.Cooper and Eromanga oils were expelled over a wide maturity range commencing at 0.6 per cent calculated vitrinite reflectance equivalent in some parts of the basin. Oil occurrence and expulsion maturity are controlled by variations in source quality such that no single expulsion threshold can be applied basin-wide. The full oil potential of the basin will only be realised by selective drilling of prospects with access to source rocks in the 0.60-0.95 per cent vitrinite reflectance range.The timing of oil expulsion is determined by using oil maturity data to calibrate thermal modelling of basin depocentres. Peak expulsion occurred during the Cretaceous and therefore prospects with pre-Tertiary structural growth are favoured.Structural embayments with thick Permian section at the southern margin of the Cooper Basin, plus the flanks of the Patchawarra and Nappamerri troughs, are highly prospective in terms of oil source potential and will be further evaluated by drilling in 1990.
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John, B. H., and C. S. Almond. "LITHOSTRATIGRAPHY OF THE LOWER EROMANGA BASIN SEQUENCE IN SOUTH WEST QUEENSLAND." APPEA Journal 27, no. 1 (1987): 196. http://dx.doi.org/10.1071/aj86017.
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Five fully-cored and wire-line logged stratigraphic bores have been drilled by the Queensland Department of Mines, relatively close to producing oil fields in the Eromanga Basin, south-west Queensland. Correlations between the stratigraphic bores and petroleum wells have established lithologic control in an area where lithostratigraphy is interpreted mainly from wire-line logs. The Eromanga Basin sequence below the Wallumbilla Formation has been investigated, and a uniform lithostratigraphic nomenclature has been applied; in the past, an inconsistent nomenclature system was applied in different petroleum wells.Accumulation of the Eromanga Basin sequence was initiated in the early Jurassic by major epeirogenic downwarping; in the investigation area the pre-Eromanga Basin surface consists mainly of rocks comprising the Thargomindah Shelf and the Cooper Basin. The lower Eromanga Basin sequence in the area onlaps the Thargomindah Shelf and thickens relatively uniformly to the north-west. The sequence comprises mainly Jurassic/Cretaceous terrestrial units in which vertical and lateral distribution is predominantly facies-controlled. These are uniformly overlain by the mainly paralic Cadna-owie Formation, signalling the initiation of a major Cretaceous transgression over the basin.The terrestrial sequence over most of the area comprises alternating coarser and finer-grained sedimentary rocks, reflecting major cyclical changes in the energy of the depositional environment. The Hutton Sandstone, Adori Sandstone and 'Namur Sandstone Member' of the Hooray Sandstone comprise mainly sandstone, and reflect high energy fluvial depositional environments. Lower energy fluvial and lacustrine conditions are reflected by the finer-grained sandstone, siltstone and mudstone of the Birkhead and Westbourne Formations, and 'Murta Member' of the Hooray Sandstone. Similar minor cycles are represented in the 'basal Jurassic' unit. The Algebuckina Sandstone, recognised only in the far south-west of the investigation area, comprises mainly fluvial sandstones.
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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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Borazjani, S., D. Kulikowski, K. Amrouch, and P. Bedrikovetsky. "Composition changes of hydrocarbons during secondary petroleum migration." APPEA Journal 58, no. 2 (2018): 784. http://dx.doi.org/10.1071/aj17127.
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We investigate secondary migration of hydrocarbons with significant composition difference between the source and oil pools in the Cooper-Eromanga Basin, Australia. The secondary migration period is significantly shorter than the time of the hydrocarbon pulse generation, so neither adsorption nor dispersion of components can explain the concentration difference. The filtration coefficients, obtained from oil compositions in source rock (Patchawarra Formation) and in the reservoir (Poolowanna Formation and Hutton Sandstone), monotonically increase as carbon number increases. The monotonicity takes place for heavy hydrocarbons (n > 10). Loss of monotonicity for light and intermediate hydrocarbons can be explained by their evaporation into the gas phase. The evaporation of light and intermediate hydrocarbons into the gas phase is supported by their concentrations in oil, which are higher in source rock than in trapped reservoir oil. The paper proposes deep bed filtration of hydrocarbons with component kinetic retention by the rock. Introduction of the component capture rate into the mass balance transport equation allows matching the concentration difference, and the tuned filtration coefficients are in the common range. The results suggest that deep bed filtration controls the final reservoir oil composition during secondary migration in the Cooper-Eromanga Basin petroleum system, which was not previously considered.
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Shirley, Erin. "Investigating depth structure uncertainty for horizontal well placement, Bauer Field, Cooper-Eromanga Basin." APPEA Journal 58, no. 2 (2018): 865. http://dx.doi.org/10.1071/aj17198.
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The Bauer Field was discovered in August 2011 on the Western Flank of the Cooper-Eromanga Basin. Bauer 1 discovered an 11 m oil column in the Namur Sandstone, directly overlain by a 4 m oil column in the McKinlay Member. The Bauer Field has been developed by vertical wells targeting the high deliverability Namur Sandstone with the McKinlay Member as a secondary target. In 2017 the decision was made to specifically target the McKinlay Member with a horizontal well, requiring a multi-disciplinary approach to combine geological, geophysical and engineering datasets. The McKinlay Member is 3–5 m in thickness and below seismic resolution with the wavelet being dominated by the larger acoustic impedance contrast produced from the Namur Sandstone. The McKinlay Member depth structure was mapped using various depth conversion methods to investigate the uncertainty in the depth structure expected for the landing of the well and along the lateral section. An average depth surface generated from the different techniques was useful for providing the general form of the structure and was used to predict dip changes along the lateral section. Understanding the uncertainty led to successful well placement of the first horizontal well in the McKinlay Member on the Western Flank.
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Boult, P. J., E. Lanzilli, B. H. Michaelsen, D. M. McKirdy, and M. J. Ryan. "A NEW MODEL FOR THE HUTTON/BIRKHEAD RESERVOIR/SEAL COUPLET AND THE ASSOCIATED BIRKHEAD-HUTTON(!) PETROLEUM SYSTEM." APPEA Journal 38, no. 1 (1998): 724. http://dx.doi.org/10.1071/aj97048.
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Biomarker analysis of source rocks and oils from the Permian and Jurassic of the central Patchawarra Trough and the Gidgealpa area, reveal that much of the oil in the Eromanga Basin may have a significant lateral migrational component and be of Jurassic (i.e. intra-Eromanga) origin. Differences in hopane signatures can be used to discriminate between palaeo-oil and presently migrating live oil, and to constrain migration pathways. Thus, in some locations the identification of new source kitchens has been made possible by a combination of seal and biomarker analysis taking into account stratigraphic inheritance on conventional structural drainage maps. 3D seismic, sequence stratigraphy, dipmeter interpretation and neodymium model age dating together with conventional correlation techniques, have provided a new model for the deposition of the Hutton Sandstone to Birkhead Formation transition in the Eromanga Basin. Analysis of seal and carrier bed properties through time, in combination with hydrocarbon geochemistry and thermal modelling, indicates that the Birkhead-Hutton (!)' petroleum system has produced significant quantities of oil in the Cooper Basin sector of the Eromanga Basin.A disconf ormity near the base of the Hutton/Birkhead transition has controlled the location of oil-prone source rocks within the Birkhead Formation and stratigraphically focussed migration along palaeo-topographic ridges. A diachronous influx of volcanic-arc-derived (VAD) sediment within the Birkhead Formation has been traced right across the productive part of the Eromanga Basin. This influx of VAD sediment is associated with the main seal to underlying accumulations within both the lower Birkhead Formation and Hutton Sandstone. Sands comprising VAD sediment, which are juxtaposed, form the weak link within the main seal. The sediments between the VAD influx and the underlying unconformity in many locations constitute a waste zone.Palaeo-oil columns are common beneath extant, live oil accumulations. This indicates that a possible decrease in seal potential of the VAD sediment has occurred over time. The main seals to underlying accumulations were originally static, water-wet capillary seals which, mostly through an alteration of wettability, changed to simple permeability seals for currently migrating oil. Seal analysis, biomarker studies and geothermal modelling indicate that a double migration pulse has occurred in some areas of the Eromanga Basin. Palaeo-oil columns are related to a Late Cretaceous charge, and live oil accumulations to presently migrating oil.
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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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Lowry, David, and David Evans. "Eromanga (Queensland) exploration–new concepts for an old basin." APPEA Journal 51, no. 1 (2011): 333. http://dx.doi.org/10.1071/aj10021.
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Eromanga Basin exploration surged in Queensland after the discovery of the Jackson field in 1982, but has ebbed over the last 20 years. Perceived exploration risks are: • Oil generation and migration peaked in the mid-Cretaceous before much of the anticlinal structuring, so that modern structure is an uncertain guide to Cretaceous migration paths. • Permian coals are generally credited with sourcing most of the oil and gas in the Cooper-Eromanga Basin. In Queensland, the Permian largely drains to the southern flank and the northern flank is thought to have a high charge risk. This study covers 100,000 km2. It used sonic logs to determine the amount of Tertiary erosion and thus allows the preparation of structure maps restored to mid-Cretaceous time. Maturity maps of the Birkhead and Poolowanna Formations were computed from a reflectance/restored temperature algorithm based on 50 wells. Source rock thickness maps and an oil expulsion model based on Pepper and Corvi (1995a, 1995b) then allowed oil expulsion to be mapped regionally. The study produces the key results that could be expected from 3D earth modelling, but with great savings in time and money. The study demonstrates an oil kitchen at both Poolowanna and Birkhead stratigraphic levels in the vicinity of Tanbar–1. Secondary migration losses are speculative, but modelling shows that hundreds of millions of barrels of oil from each formation have migrated west towards the Curalle ridge, north to Inland and Morney, and southeast to Mt Howitt. The Inland oil field is presently an isolated anomaly on the northwest flank of the basin, but this study suggests that further exploration in the area could be successful.
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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., and K. Amrouch. "4D modelling of fault reactivation using complete paleostress tensors from the Cooper–Eromanga Basin, Australia." Australian Journal of Earth Sciences 65, no. 5 (May 15, 2018): 661–81. http://dx.doi.org/10.1080/08120099.2018.1465472.
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Tinapple, Bill. "Australian states and Northern Territory acreage update at APPEA 2011." APPEA Journal 51, no. 1 (2011): 79. http://dx.doi.org/10.1071/aj10004.
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Bill’s presentation is on behalf of the NT, Queensland, NSW, Victoria, SA and WA. Some highlights are: • NT: 24 onshore exploration applications were received in 2010 (an increase of 50 % from 2009). About 479,100 sq km of the NT is now under application, including grassroots areas. • Queensland: In 2011, a variety of exploration opportunities are being offered in basins ranging in age from Precambrian to Cretaceous. Targets include conventional oil and gas as well as shale gas. • NSW: There are now more than 800 unallocated petroleum exploration blocks, including the Darling Basin, the Tamworth Moratorium area, and the Oaklands Basin Moratorium area. • Victoria: Acreage release is proposed for the onshore Otway Basin in 2011. • SA: The CO2010 acreage release, comprising three blocks in the Cooper and Eromanga basins, closed on 10 March 2011. • WA: To coincide with the APPEA Conference, acreage has been made available for bidding from the Canning Basin, Northern Carnarvon Basin, Officer Basin and Perth Basin.
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Molyneux, S. J., H. F. Wu, S. Delaney, and A. Gongora. "Outcome focused: how to deliver value in a field (re)development. A case study from the Cooper–Eromanga Basin, South Australia." APPEA Journal 60, no. 2 (2020): 491. http://dx.doi.org/10.1071/aj19030.
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The share of global hydrocarbon production from ‘aging’ assets is increasing, whereas global demand for energy continues to increase at 1–2% per year (IEA 2019). In 2018, the International Energy Agency estimated the global average production decline at 4% per annum (Gould and McGlade 2018). Production from many of Australia’s established basins, such as the Cooper–Eromanga basin and the North West Shelf, is dominated by aging assets. To arrest this decline, actions must be taken to meet global demand for oil and gas, sustain production and underpin shareholder expectations of a return on their investment. Arresting field decline is a multifaceted problem. A single fix, whether technological or operational, will not maximise production or asset value. Any project to arrest field decline, grow production or (re)develop a field must be considered in its entirety, as an integrated system, by a multidisciplinary team. In addition, and critical to success, the required outcome must be clearly established and committed to by field owners, consultants and staff assigned to the project. This paper demonstrates how using a committed, outcome-focused approach, an integrated project team identified field redevelopment opportunities that significantly increased estimated ultimate recovery in an aging oilfield (that had already produced more than 70–80% of the developed resource) in the Cooper–Eromanga basin, South Australia. Factors critical to success were: (1) a commitment to look at all aspects of the field, from geology and geophysics, through the completion, well and field performance and operational infrastructure to identify development opportunities; (2) an ability to be agile, cycling quickly through the workflow as new information became available; (3) dedicated resources, clear communication and a commitment to integrated work across consultant and staff resources; and (4) management support.
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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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Kulikowski, David, Catherine Hochwald, Dennis Cooke, and Khalid Amrouch. "A Statistical Approach to Assessing Depth Conversion Uncertainty on a Regional Dataset: Cooper-Eromanga Basin, Australia." ASEG Extended Abstracts 2016, no. 1 (December 2016): 1–7. http://dx.doi.org/10.1071/aseg2016ab200.
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Sun, Xiaowen. "Structural Style of the Warburton Basin and Control in the Cooper and Eromanga Basins, South Australia." Exploration Geophysics 28, no. 3 (June 1997): 333–39. http://dx.doi.org/10.1071/eg997333.
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Kulikowski, David, Khalid Amrouch, Dennis Cooke, and Michael Edward Gray. "Basement structural architecture and hydrocarbon conduit potential of polygonal faults in the Cooper-Eromanga Basin, Australia." Geophysical Prospecting 66, no. 2 (May 25, 2017): 366–96. http://dx.doi.org/10.1111/1365-2478.12531.
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Archer, John, Milos Delic, and Frank Nicholson. "Innovative high trace density design with broadband seismic data acquisition in the Cooper–Eromanga Basins, Australia." APPEA Journal 58, no. 2 (2018): 773. http://dx.doi.org/10.1071/aj17111.
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Through a combination of innovative survey design, new technology and the introduction of novel operational techniques, the trace density of a 3D seismic survey in the Cooper Basin was increased from a baseline of 140 000 to 1 600 000 traces km–2, the bandwidth of the data was extended from four to six octaves, and the dataset was acquired in substantially the same time-frame and for the same cost as the baseline survey.
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Keany, Mitchell, Simon Holford, and Mark Bunch. "Constraining Late Cretaceous exhumation in the Eromanga Basin using sonic velocity data." APPEA Journal 56, no. 1 (2016): 101. http://dx.doi.org/10.1071/aj15009.
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Exhumation in sedimentary basins can have significant consequences for their petroleum systems. For example, source rocks may be more mature than their present-day burial depths suggest, increased compaction can result in reduced reservoir quality, and seal integrity problems are commonly encountered. The Eromanga Basin in central Australia experienced an important phase of exhumation during the Late Cretaceous, though the magnitude and spatial distribution of exhumation is poorly constrained. In this study exhumation magnitudes have been determined for 100 petroleum wells based on sonic transit time analyses of fine grained shales, siltstones and mudstones within selected Cretaceous stratigraphic units. Observed sonic transit times are compared to normal compaction trends (NCTs) determined for suitable stratigraphic units. The Winton Formation and the Bulldog Shale/Wallumbilla Formation were chosen for analysis in this study for their homogenous, fine-grained and laterally extensive properties. Exhumation magnitudes for these stratigraphic units are statistically similar. Results show net exhumation in the southern Cooper-Eromanga Basin (<500 m [~1,640 ft]) and higher net exhumation magnitudes (up to 1,400 m [~3,937 ft]) being recorded in the northeastern margins of the basin. Gross exhumation magnitudes show significant variation across short distances suggesting different tectonic processes acting upon the basin. Independent vitrinite reflectance and apatite fission track analysis data, available for a subset of wells, give statistically similar exhumation magnitudes to those that have been calculated through the compaction methodology, giving confidence in these results. The effect on source rock generation is illustrated through 1D basin modelling where exhumation is shown to impact the timing and type of the hydrocarbons generated. The improved quantification of this exhumation permits a better understanding of the Late Cretaceous tectonics and palaeogeography of central Australia.
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Troup, Alison, and Behnam Talebi. "Adavale Basin petroleum plays." APPEA Journal 59, no. 2 (2019): 958. http://dx.doi.org/10.1071/aj18083.
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The Devonian Adavale Basin system is an under-explored, frontier petroleum basin in south-west Queensland. It has a confirmed petroleum system with production from the Gilmore gas field. The age, marine depositional environments and high carbonate content suggest the basin may have unconventional petroleum potential, and there has been renewed interest from industry in evaluating the basin. In support of this, the Queensland Department of Natural Resources, Mines and Energy has examined the source rock properties of the Bury Limestone and Log Creek Formation and has commissioned an update to the SEEBASE® interpretation of the region. Gas- to oil-mature source rocks are found in deep marine shales of the Log Creek Formation, with secondary potential in the shelfal Bury Limestone. The main known reservoir within the Adavale Basin is the Lissoy Sandstone, though sandstones found in other units may also have tight reservoir potential. These petroleum systems elements form several plays, including conventional clastic structural targets, carbonate plays, including possible reef targets, and salt plays associated with doming from the Boree Salt. Potential unconventional targets include tight sandstone, shale and limestone, with recent analysis of an organic-rich marl from the Bury Limestone indicating good retention properties. The overlying Cooper, Galilee and Eromanga basins also contain potential reservoirs for hydrocarbons generated in the Adavale Basin and Warrabin Trough.
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Manka, Anna, Glen Buick, Rob Menpes, Luke Gardiner, Cameron Jones, and Khalid Amrouch. "Effects of near surface lithology on velocity modelling and time–depth relationships in the Cooper–Eromanga–Lake Eyre Basin." APPEA Journal 58, no. 1 (2018): 321. http://dx.doi.org/10.1071/aj17158.
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Structural closures on the western flank of the Patchawarra Trough in the Cooper–Eromanga Basin are truly low relief; drilling opportunities regularly target hydrocarbon columns of similar magnitude to the uncertainty of depth prediction. Improving the accuracy and precision of depth prediction will reduce risk for drilling opportunities, and improve drilling success rates. A detailed study of the near surface geology (surface to ~500 m depth) of the western flank of the Patchawarra Trough has been undertaken to better understand the effect of observed geological variations of the near surface on depth prediction at deeper target levels. The stratigraphic interval investigated includes the top of the Eromanga Basin and the entire Lake Eyre Basin, which is sparingly studied and routinely overlooked in the statics and velocity modelling process. This study analysed recently acquired cased-hole sonic logs in conjunction with gamma logs and mudlog data to map out the observed geological variations, and construct a 3D velocity model of the near surface. Variations of layer thickness and seismic velocity were input into Monte Carlo simulations to investigate sensitivities of each formation on two-way travel time and depth prediction. This investigation has found that velocity variations of the Weathered Winton Formation, and thickness variations of the Namba Clastics have the greatest impact on imaging of structures at depth. Independently, these have the potential to completely conceal or create structures in the time domain. Continued efforts in improved understanding of the near surface will subsequently lead to enhanced imaging of structures, which can then be used in the mapping of structural closures in petroleum exploration and development.
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Nakanishi, T., and S. C. Lang. "THE SEARCH FOR STRATIGRAPHIC TRAPS GOES ON—VISUALISATION OF FLUVIAL-LACUSTRINE SUCCESSIONS IN THE MOORARI 3D SURVEY, COOPER-EROMANGA BASIN." APPEA Journal 41, no. 1 (2001): 115. http://dx.doi.org/10.1071/aj00006.
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Exploration and development in the Cooper-Eromanga Basin have been predominantly focussed on structural traps. However, the future for exploration and field development lies in exploration for stratigraphic traps. Using advanced visualisation techniques on open file 3D seismic survey data from the Moorari and Woolkina fields in the Patchawarra Trough, Cooper Basin, we have sought to characterise the variety of possible stratigraphic traps in the Permian Patchawarra, Epsilon and Toolachee Formations and also the basal Jurassic Poolowanna Formation. The key to the analysis lies in a genetic-stratigraphic framework using sequence stratigraphy concepts as applied to non-marine basins.Five different types of possible stratigraphic traps are illustrated from the Moorari 3D survey: Isolated fluvial channels in a transgressive systems tract of the lower Patchawarra Formation.Fluvial sand bodies in low accommodation intervals in a lowstand systems tract of the upper Patchawarra Formation.Highstand lacustrine delta of the Epsilon Formation below the regional sequence boundary at the base of the Toolachee Formation.Isolated fluvial channels in the transgressive systems tract of the Toolachee Formation.Crevasse splay channels and crevasse splay delta complex of the transgressive systems tract of the Poolowanna Formation.For each trap type, three dimensional distributions of the possible reservoir and seal rocks are presented and the ranking of stratigraphic trap opportunities is discussed.
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Randal, M. A. "PETROLEUM EXPLORATION AND DEVELOPMENTS IN QUEENSLAND DURING 1985." APPEA Journal 26, no. 2 (1986): 46. http://dx.doi.org/10.1071/aj85051.
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Petroleum exploration in Queensland during 1985 remained at the high levels that existed during 1984. Of the 115 wells spudded, 88 were wildcat exploration wells, 24 were appraisal wells, and three were development wells. New field discoveries numbered 23, being 16 oil and 7 of gas, the highest number ever recorded. All but two of the appraisal wells and all three development wells were successful. Seismic surveys totalled 23 158 km of subsurface section, 75 per cent in the western part of the state in the Eromanga/Cooper and Eromanga/Galilee basins and their environs, and the remainder in the Surat and Bowen basins. Similar levels of exploration are expected during 1986, although the amount of seismic surveying may decrease as much as 20 per cent. Exploration is expected to be in mostly the same basins as now over the next 15 years.Two liquefied petroleum gas (LPG) separating plants came on stream in 1985 in the Surat/Bowen Basin, one at Kincora and one near Wallumbilla, with a combined output capacity of 50 000 tonnes annually. At Eromanga a mini-refinery with a capacity of about 880 barrels of oil per day commenced operations producing mostly distillate. Petroleum Leases were granted during the year over the Tintaburra and Bodalla South oilfields near Eromanga, and over the Riverslea and Yapunyah oilfields in the Surat region.Queensland's petroleum reserves now stand at 66 million barrels remaining recoverable oil, 17 billion cu m gas, and 500 000 tonnes of LPG. Daily production is about 29 000 barrels of oil and condensate, about 1.2 million cu m of gas, and 97 tonnes of LPG.There is relatively little impact to petroleum exploration in Queenland through the setting aside of land for special purposes. Legislation and administrative arrangements allow exploration in National Parks and Forest Reserves under conditions set down by the controlling bodies.
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Cockerill, Ian. "Australian exploration review 2020." APPEA Journal 61, no. 2 (2021): 331. http://dx.doi.org/10.1071/aj21006.
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Australian exploration battled on through the challenging headwinds of 2020 and surprisingly, 2020 saw an increase in exploration drilling on 2019 activity. Twenty-five exploration wells were drilled in 2020 versus 20 exploration wells drilled in 2019. Eight discoveries were made during the year, with the most significant being the Enterprise discovery in the Otway Basin. 2020 also saw a return to exploration drilling in the Beetaloo Sub-basin unconventional plays. Appraisal drilling was dominated by Cooper-Eromanga Basin and coal seam gas activity. There were no offshore appraisal wells in 2020. The exploration farm-in deals of note were Santos taking additional equity from Armour in their South Nicholson Basin unconventional project and Origin taking additional equity from Falcon in their Beetaloo Sub-basin unconventional project. Origin also farmed into the Canning Basin position of Buru Energy and Rey Resources. Australia is set for an exciting year of exploration ahead with a return to exploration drilling in the Bedout Sub-basin, further exploration drilling in the North Perth Basin and a continuation of drilling and testing of the unconventional plays in the Beetaloo Sub-basin.
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Lang, S. C., P. Grech, R. Root, A. Hill, and D. Harrison. "THE APPLICATION OF SEQUENCE STRATIGRAPHY TO EXPLORATION AND RESERVOIR DEVELOPMENT IN THE COOPER-EROMANGA-BOWEN-SURAT BASIN SYSTEM." APPEA Journal 41, no. 1 (2001): 223. http://dx.doi.org/10.1071/aj00011.
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The application of sequence stratigraphy to non-marine strata in intracratonic basins is still in its infancy, however, the predominantly non-marine Cooper- Eromanga-Surat-Bowen basin system of Eastern Australia provides an excellent opportunity to demonstrate how sequence stratigraphic concepts can be applied to non-marine successions to assist with exploration and reservoir development. The key to applying sequence stratigraphic concepts in non-marine basins lies in understanding the role of alluvial sediment accommodation relative to sediment supply. Accommodation is created by a combination of tectonic subsidence, compaction and changing water tables in floodplain lakes, marshlands and peat mires. If the alluvial basin is directly connected to the marine system then eustacy may influence accommodation in the lower reaches of the alluvial network, but its effect will significantly diminish upstream depending on the slope. Climate change will, however, have an impact on fluvial discharge, rising water tables, floodplain lake levels, and sediment flux. For sediments to accumulate, accommodation must be positive, whereas negative accommodation leads to erosion. Fluvial accommodation is, therefore, comparable with the concept of base-level. During an episode of basin-wide tectonic uplift or tilting, falling base-level (negative accommodation) leads to widespread erosion on the basin margins or over intra-basinal highs, and an unconformity equivalent to a sequence boundary develops. If followed by a period of low accommodation, rivers rework much of their floodplain, resulting in a sheetlike, amalgamated succession of predominantly sandy bedload deposits of high nett to gross, equivalent to an alluvial lowstand. Further downstream, lowstand deltas may form in the lakes.
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Hallmann, C. O. E., K. R. Arouri, D. M. McKirdy, and L. Schwark. "A NEW PERSPECTIVE ON EXPLORING THE COOPER/EROMANGA PETROLEUM PROVINCE—EVIDENCE OF OIL CHARGING FROM THE WARBURTON BASIN." APPEA Journal 46, no. 1 (2006): 261. http://dx.doi.org/10.1071/aj05015.
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The history of petroleum exploration in central Australia has been enlivened by vigorous debate about the source(s) of the oil and condensate found in the Cooper/Eromanga basin couplet. While early workers quickly recognized the source potential of thick Permian coal seams in the Patchawarra and Toolachee Formations, it took some time for the Jurassic Birkhead Formation and the Cretaceous Murta Formation to become accepted as effective source rocks. Although initially an exploration target, the Cambrian sediments of the underlying Warburton Basin subsequently were never seriously considered to have participated in the oil play, possibly due to a lack of subsurface information as a consequence of limited penetration by only a few widely spaced wells. Dismissal of the Warburton sequence as a source of hydrocarbons was based on its low generative potential as measured by total organic carbon (TOC) and Rock-Eval pyrolysis analyses. As most of the core samples analysed came from the upper part of the basin succession that has been subjected to severe weathering and oxidation, these results might not reflect the true nature of the Warburton Basin’s source rocks. We analysed a suite of source rock extracts, DST oils and sequentially extracted reservoir bitumens from the Gidgealpa field for conventional hydrocarbon biomarkers as well as nitrogen-containing carbazoles. The resulting data show that organic facies is the main control on the distribution of alkylated carbazoles in source rock extracts, oils and sequentially extracted bitumens. The distribution pattern of alkylcarbazoles allows to distinguish between rocks of Jurassic, Permian and pre-Permian age, thereby exceeding the specificity of hydrocarbon biomarkers. While no pre-Permian signature can be found in the DST oils, it is present in sequentially extracted residual oils. However, the pre-Permian molecular source signal is diluted beyond recognition during conventional extraction procedures. The bitumens that are characterised by a pre-Permian geochemical signature derive from differing pore-filling oil pulses and exhibit calculated maturities of up to 1.6% Rc, thereby proving for the first time the petroleum generative capability of source rocks in the Warburton Basin.
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Sun, X. W. "PREDICTION OF CARBONATE RESERVOIRS AND TRAPS BY APPLYING SEQUENCE STRATIGRAPHY IN THE EASTERN WARBURTON BASIN, SOUTH AUSTRALIA." APPEA Journal 38, no. 1 (1998): 380. http://dx.doi.org/10.1071/aj97018.
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The Early Palaeozoic eastern Warburton Basin unconformably underlies the Cooper and Eromanga Basins. Four seismic sequence sets (I−IV) are interpreted. Among them, sequence set II is subdivided into four Cambro-Ordovician depositional sequences. Sequence 1, the oldest, is a shallow shelf deposit that occurs only in the Gidgealpa area. Sequences 2 and 3 were deposited in a wider area; from west to east, environments varyied from deep siliciclastic ramp, carbonate inner-shelf, peritidal, shelf edge, and slope-to-basin. Their seismic reflection configurations are high-amplitude, regionally parallel-continuous, layered patterns, locally mounded geometry, as well as divergent-fill patterns. Sequence 4, the youngest, was deposited in a mixed siliciclastic and carbonate, storm-dominate shelf. Its seismic reflection configurations are moderate amplitude, parallel-layered patterns, decreasing in amplitude upwards.Boundaries between the four sequences generated good secondary porosity in the carbonates. Karst development is interpreted to have generated much of this porosity in shelf and peritidal carbonates, and carbonate build-ups. Shoal-water sandy limestone and calcareous sandstone of Sequence 4 may be other potential reservoir rocks. Potential source rocks comprise mudstone and shale of slope and basin lithofacies. There are two kinds of stratigraphic trap. One is in Sequences 2 and 3, associated with high-relief carbonate build-ups encased in lagoonal mudstone and shelf edge sealed by transgressive siltstone and shale. The other is a transgressive marine shale enclosing porous dolostone of the karstified Sequence 1. In addition, petroleum may have migrated from Permian source rocks of the Cooper Basin to karstified carbonate reservoirs of the Warburton Basin at unconformities.
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Boult, P. J., P. N. Theologou, G. A. Johnson, and M. Carbone. "PROBE PERMEABILITY STUDIES FOR BETTER RESERVOIR UNIT EVALUATION WITH EXAMPLES FROM THE TIRRAWARRA SANDSTONE, COOPER BASIN AND THE MURTA AND MCKINLAY MEMBERS, EROMANGA BASIN." APPEA Journal 35, no. 1 (1995): 132. http://dx.doi.org/10.1071/aj94009.
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Probe permeametry studies have enabled a better understanding of permeability characteristics of three clastic reservoirs: The Tirrawarra Sandstone in the Tirrawarra and Gidgealpa fields of the Cooper Basin and the Murta and McKinlay Members in the Jena and Biala fields of the Eromanga Basin.An empirical relationship between Hassler-sleeve core plug measurements and probe permeametry is used for calibration. The probe permeameter takes sufficient non-destructive readings to define permeability better within an individual facies or reservoir flow unit.Frequency versus log (permeability) plots and semi-variograms allow visual comparison of individual reservoirs and facies. Histograms of plug and probe data show similar distributions, but the plug data generally have a lower variance than the probe data.For the Tirrawarra Sandstone there is a better match between probe permeability data and wireline predicted permeability than between the latter and core plug permeability.Azimuth directional permeability is evident for the braided fluvial sands of the Tirrawarra Sandstone. Permeability within the measured formations is primarily related to depositional facies. Secondary reduction in permeability within the Tirrawarra Sandstone is mainly due to ductile rock fragment compaction and authigenic clay precipitation with possible groundwater flow control in the Gidgealpa field.
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Nakanishi, T., and S. C. Lang. "TOWARDS AN EFFICIENT EXPLORATION FRONTIER: CONSTRUCTING A PORTFOLIO OF STRATIGRAPHIC TRAPS IN FLUVIAL-LACUSTRINE SUCCESSIONS, COOPER-EROMANGA BASIN." APPEA Journal 42, no. 1 (2002): 131. http://dx.doi.org/10.1071/aj01008.
Full textAbstract:
In the Cooper-Eromanga Basin, the future of exploration lies in identifying an appropriate exploration portfolio consisting of stratigraphic traps in structurally low or flank areas. A variety of stratigraphic trap prospects in the Moorari and Pondrinie 3D seismic survey areas are identified in the Patchawarra, Epsilon, Toolachee and Poolowanna formations. To identify the stratigraphic traps, an integration of sequence stratigraphic concepts applied to non-marine basins and advanced 3D seismic data visualisation was employed. This paper focusses on estimating the chance of geologic success and the probabilistic reserves size for each prospect within its sequence stratigraphic context (lowstand, transgressive or highstand systems tracts). The geologic chance factors for an effective stratigraphic trap include reservoir, top seal, lateral seal and bottom seal within each depositional systems tract, the seal effectiveness of the adjacent depositional systems tracts and the appropriate spatial arrangement of these factors. The confidence values for the existence of geologic chance factors were estimated according to the distributions of the possible reservoir and seal rocks within each genetic-stratigraphic interval and the chance of geologic success of each prospect was calculated. For probabilistic reserves estimation, geologically reasonable ranges were estimated for each parameter employing Monte Carlo simulation to calculate the reserves distribution. When a series of possible exploration portfolios, including single or multiple prospects from the prospect inventory are plotted in terms of the chance of geologic success vs. the mean value of the reserves estimate, an efficient exploration frontier emerges. The portfolio candidates on the efficient exploration frontier were assessed with regard to chance of economic success and expected net present value (ENPV) using a simple cash flow model. The results indicate that appropriate portfolios include multiple prospect exploration especially with lowstand systems tract plays using single or multiple exploration wells. The portfolio construction approach for stratigraphic trap exploration should ultimately be made consistent with conventional play types, to enable an assessment of all exploration opportunities.
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Troup, Alison, and Sally Edwards. "Source rock characterisation of under-explored regions of Queensland." APPEA Journal 56, no. 2 (2016): 580. http://dx.doi.org/10.1071/aj15086.
Full textAbstract:
Historically, petroleum exploration in Queensland has focused on the Bowen-Surat and Cooper-Eromanga basins, with only cursory examination of other basins across the state. As part of the Queensland Industry Priorities Initiative, two projects (Round 1 and 2) were submitted to the Geological Survey of Queensland (GSQ) to examine the geochemical characteristics of potential petroleum source rocks throughout Queensland. The analysis conducted provides a better understanding of generative potential for petroleum, and predicts the timing, volume, composition, and physical state of hydrocarbons retained in and expelled from source rocks. It is an integral component to petroleum systems analysis used to identify the potential for undiscovered accumulations of petroleum from conventional and unconventional reservoirs. Of particular interest were the Georgina, Drummond, Eromanga, and Maryborough basins. Of these, the Georgina and Maryborough basins have known hydrocarbon shows identified through exploration drilling, though no commercial discoveries have yet been made. The Drummond Basin was targeted to identify a potential source for oil and gas shows encountered in drilling within the Galilee Basin. The Toolebuc Formation in the Eromanga Basin has been noted as having the potential for a shale oil play and this study is supporting further assessment to identify optimal areas for future exploration through predictive modelling. This report details the results from Round 1 of the study for samples taken from the Georgina Limestone and Scartwater, Ducabrook, Mount Hall, Toolebuc, and Maryborough formations, where limited analysis of source rock characteristics has historically been undertaken. Ninety-seven samples were chosen from nine wells and sent to Geos4 in Potsdam, Germany, for source rock analysis. All samples were screened for suitability of further analysis using Rock-Eval and TOC by LECO, with immature and organic-rich samples being preferentially selected for further testing. Screened samples were analysed using pyrolysis gas chromatography (n=27), thermovaporisation (n=23), bulk kinetics (n=5), compositional kinetics (n=4), late gas analysis (n=14), and biomarker and bulk isotope analysis (n=15). These results have been integrated with existing analyses to better understand the prospectivity of the under-explored basins of Queensland.
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Mortimore, P. W. Vincent I. R., and D. M. McKirdy. "HYDROCARBON GENERATION, MIGRATION AND ENTRAPMENT IN THE JACKSON-NACCOWLAH AREA, ATP 259P, SOUTHWESTERN QUEENSLAND." APPEA Journal 25, no. 1 (1985): 62. http://dx.doi.org/10.1071/aj84005.
Full textAbstract:
The northern part of the Naccowlah Block, situated in the southeastern part of the Authority to Prospect 259P in southwestern Queensland, is a major Eromanga Basin hydrocarbon province. The Hutton Sandstone is the main reservoir but hydrocarbons have been encountered at several levels within the Jurassic-Cretaceous sequence. In contrast, the underlying Cooper Basin sequence is generally unproductive in the Naccowlah Block although gas was discovered in the Permian at Naccowlah South 1. Oil and gas discoveries within the Eromanga Basin sequence are confined to the Naccowlah-Jackson Trend. This trend forms a prominent high separating the deep Nappamerri Trough from the shallower, more stable northern part of the Cooper Basin.The Murta Member is mature for initial oil generation along the Naccowlah-Jackson Trend and has sourced the small oil accumulations within this unit and the underlying Namur Sandstone Member. The Birkhead Formation is a good source unit in this area with lesser oil source potential also evident in the Westbourne Formation and 'basal Jurassic'. Source quality and maturation considerations imply that much of the oil discovered in Jurassic reservoirs along the Naccowlah-Jackson Trend was generated from more mature Jurassic source beds in the Nappamerri Trough area to the southwest. Maturation modelling of this deeper section suggests that hydrocarbon generation from Jurassic source units commenced in the Early Tertiary. Significant oil generation and migration has therefore occurred since the period of major structural development of the Naccowlah-Jackson Trend in the Early Tertiary. This trend, however, has long been a major focus for hydrocarbon migration paths out of the Nappamerri Trough as a result of intermittent structuring during the Mesozoic. Gas reservoired in Jurassic sandstones at Chookoo has been generated from more mature Jurassic source rocks in the deeper parts of the Nappamerri Trough.Permian sediments in the Nappamerri Trough area are overmature for oil generation and are gas prone. Gas generated in this area has charged the lean Permian gas Field at Naccowlah South, along the Wackett-Naccowlah- Jackson Trend. North of this trend Permian source rocks are mainly gas prone but more favourable levels of maturity allow the accumulation of some gas liquids and oil. However, geological and geochemical evidence suggests that Permian sediments did not source the oil found in Jurassic-Cretaceous reservoirs in the Jackson- Naccowlah area.
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Hodge, C. C., N. J. Russell, and M. Smyth. "THE SIGNIFICANCE OF HYDROCARBON SHOWS AND OIL RECOVERIES IN THE LONGREACH AREA, CENTRAL QUEENSLAND." APPEA Journal 29, no. 1 (1989): 157. http://dx.doi.org/10.1071/aj88017.
Full textAbstract:
In 1925, over 40 gallons of oil were recovered from the Longreach town- water well. More recently, Corona 1, drilled by the ATP 271P Joint Venture in 1984, recovered 9 m (0.5 bbls) of oil in the drill pipe.These oil recoveries, along with several water- bore oil and gas occurrences, are all located in the Longreach area, Central Queensland, over 100 km north- northeast of the Cooper Basin zero edge. The oil recoveries and shows are therefore considered to be the product of source rocks other than those of the Cooper Basin.The Birkhead Formation, the unit considered most likely to source the Longreach and Corona oils, has been studied with a view to understanding the nature of hydrocarbon generation in the vicinity of the Maneroo Platform. The variables measured include (1) thickness of the shale units, (2) volume and type of dispersed organic matter (DOM) and (3) maturity (vitrinite reflectance). Measurements were taken from 10 exploration wells through the whole formation to provide uniform comparative assessment.The Birkhead Formation in the Maneroo Platform area is shown to have an anomalously low sandstone- to- shale ratio, vitrinite reflectance values (Rm(o)) consistently greater than 0.7 per cent and a favourable petroleum generative geochemistry.These results emphasise the highly variable nature of the Eromanga Basin sequence, and therefore its diverse generative potential, and highlight the encouraging prospectivity of the Maneroo Platform area despite the present lack of commercial oil discoveries.
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Dolan, P., P. D. Griffiths, and S. R. Welton. "THE SUCCESSFUL RECOVERY OF WELL PRODUCTIVITY IN THE BODALLA SOUTH OILFIELD." APPEA Journal 28, no. 1 (1988): 7. http://dx.doi.org/10.1071/aj87001.
Full textAbstract:
The Bodalla South oilfield is located in the Cooper-Eromanga Basin, south-west Queensland. The field consists of two main oil reservoirs, the Hutton and basal Jurassic sandstones of the Eromanga Basin sequence. Several of the development wells drilled into these reservoirs exhibited high skin factors which resulted in reduced well productivities. These skin factors were also seen to increase with production from these wells. Core studies on samples from the Hutton and basal Jurassic reservoirs revealed the presence of migrating fines and showed that the fines were predominantly kaolinite clay particles. A formation damage study showed that the initial formation damage, created by drilling and completion operations, acted as a barrier to these mobile fines and resulted in the increasing formation damage. The study concluded that the damage can be removed by the underbalance re-perforation of the particular intervals.A four well workover program was undertaken at Bodalla South with the aim of the underbalance re-perforation of producing intervals with substantial formation damage. These complex workovers involved dual string tubing-conveyed perforation operations along with appropriate completion techniques. A mixed KCl/NaCl brine containing a clay stabiliser was used and was filtered through a filter cartridge system to remove all particles greater than 10 microns. Compressed nitrogen from standard gas bottles was used along with crude oil to achieve the 1 000 psi underbalance required for the re-perforation of the reservoir intervals.The workovers were very successful in restoring the productivity of the damaged intervals; in one case, oil production increased from 160 b/d to around 1 600 b/d. This improved production performance has been sustained. The workovers were complex and expensive, costing in total around A$800 000. However, payback was achieved, in one instance, within one month.
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Troup, Alison, and Peter Green. "The changing face of Queensland's petroleum industry." APPEA Journal 51, no. 1 (2011): 225. http://dx.doi.org/10.1071/aj10016.
Full textAbstract:
The cycles and related changes in exploration targets identified in this study show the evolution of the Queensland petroleum industry from conventional petroleum to coal seam gas dominance. Delineation of these cycles was undertaken using petroleum exploration well data, and production and reserves statistics. Although the cycles are defined on the basis of exploration activity, there is a very different history in the types of targets and commodities explored for in the Bowen-Surat and Cooper-Eromanga basins. Trends in exploration success have been influenced by technology improvements, better understanding of target reservoirs, proximity to infrastructure, government policy and world oil prices. Four distinct exploration cycles have been identified from the data. During the first cycle (1959–74) exploration focused predominantly on the shallower Jurassic-aged reservoirs in the Bowen-Surat basins resulting in the discovery of most of the major conventional oil and gas fields. The second cycle (1979–89) saw exploration begin in earnest in the Cooper-Eromanga basins and a switch to predominantly Triassic-aged reservoirs in the Bowen-Surat basins. The first coal seam gas exploration wells were drilled during this cycle. The third cycle (1990–99) shows a decrease in the number of conventional petroleum wells across both regions and the beginning of the switch to the present dominance of coal seam gas. The fourth cycle (2000–present) shows a significant decrease in the number of conventional exploration wells drilled across both regions, but an increase in the success rates. All conventional discoveries in the Bowen-Surat basins during cycle four have been in Permian-aged reservoirs, reflecting a change in the exploration focus to deeper parts of the Bowen Basin. Coal seam gas exploration has expanded significantly, with the Walloon Coal Measures being targeted, resulting in nearly four coal seam gas wells drilled for each conventional petroleum exploration well state-wide since 2000. Examination of coal seam gas exploration highlights the many false starts since the first well was drilled in 1980. Exploration has shifted from area to area as companies tested different exploration concepts and completion techniques. The most obvious shift has been from Permian-aged targets of the Bowen Basin into the Jurassic-aged Walloon Coal Measures in the Surat and Clarence-Moreton basins, as its prospectivity was realised.
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Krassay, Andrew, Jane Blevin, and Donna Cathro. "Exploration highlights for 2007." APPEA Journal 48, no. 1 (2008): 395. http://dx.doi.org/10.1071/aj07028.
Full textAbstract:
Record-high oil prices along with on-going development of infrastructure, increasing domestic demand and international LNG sales continued to drive significant investment in exploration in onshore and offshore Australia during 2007. These trends are reflected nationally by strong uptake of acreage and continued high levels of drilling activity and seismic acquisition. Overall, drilling and discovery trends were similar to 2006 which showed significant exploration activity focussed on proven hydrocarbon basins (Carnarvon, Browse, Perth and Cooper basins). Most petroleum discoveries made in 2007 were located within 10 to 15 km of existing fields. In terms of number of exploration wells, the offshore Carnarvon continued to dominate with over 20 new field wildcats drilled. Discoveries include a major deep-water gas find for BHP-Billiton at Thebe-1 on the outer Exmouth Plateau, Apache’s gas finds at Brunello–1, Julimar–1 and Julimar East–1, oil for Santos at Fletcher–1 and gas at Lady Nora–1 for Woodside. The Browse Basin saw a significant increase in drilling activity with some success. Exploration in the offshore southwest margin received a major boost with a series of shallow-water discoveries for ROC Oil in the Perth Basin with gas at Frankland–1 395and Perseverance–1 and gas and oil at Dunsborough–1. Onshore, the Cooper/Eromanga basins continued to experience the highest level of drilling activity and seismic acquisition. This activity resulted in numerous small to moderate oil discoveries for Santos, Beach Petroleum, Eagle Bay Resources, Stuart Petroleum and Victoria Petroleum. There were a few notable exceptions to near-field exploration in 2007 with several wildcats drilled in frontier regions including PetroHunter Energy and Sweetpea Petroleum’s Shanendoah–1 in the Georgina/Betaloo basins, Austin’s Gravestock–1 in the onshore Stansbury Basin and the onshore drilling campaign by ARC Energy in the Canning Basin. In Queensland, CSM exploration and discovery continued to experience strong positive growth underpinned by delivery to local markets.
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Powell, T. G. "AUSTRALIA’S HYDROCARBON PROVINCES—WHERE WILL FUTURE PRODUCTION COME FROM?" APPEA Journal 44, no. 1 (2004): 729. http://dx.doi.org/10.1071/aj03037.
Full textAbstract:
The cumulative graph of reserves added to a basin through time is a measure of that basins’ exploration maturity. Additions of reserves through new field discovery are limited in the Bowen-Surat, Gippsland, Cooper-Eromanga and Bonaparte Basins whilst significant discoveries continue to be made in the Carnarvon Basin. The recent discoveries in the Perth Basin represent a significant new phase in the addition to reserves for this basin. Reserves growth in existing fields represents a very significant source of new crude oil reserves. All gas bearing basins including those in eastern Australia show potential for additional gas discoveries. Coal Bed Methane also represents a significant gas resource into the future.Australia’s production of crude oil has averaged 11% of the remaining reserves over the last decade. In the late 90s, the rate of production has exceeded the rate of addition to reserves and production must decline in the medium term. Medium- to long-term forecasts of future crude oil production are uncertain because of the difficulty in predicting the rate of crude oil discovery, particularly since many of the established plays in established crude oil basins appear to have little remaining potential and success rates and potential for new plays in established and frontier areas of exploration is unknown.Rates of gas production are not related to existing reserves, but rather to the dynamics of the commercial market which is strongly influenced by regional infrastructure.
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Mackie, S. I., and C. M. Gumley. "THE DIRKALA SOUTH OIL DISCOVERY: FOCUSSING ON COST-EFFICIENT RESERVOIR DELINEATION." APPEA Journal 35, no. 1 (1995): 65. http://dx.doi.org/10.1071/aj94004.
Full textAbstract:
The Dirkala Field is located in the southern Murta Block of PEL's 5 and 6 in the southern Cooper and Eromanga Basins. Excellent oil production from a single reservoir sandstone in the Jurassic Birkhead Formation in Dirkala-1 had indicated a potentially larger resource than could be mapped volumetrically. The hypothesis that the resource was stratigraphically trapped led to the need to define the fluvial sand reservoir seismically and thereby prepare for future development.A small (16 km2) 3D seismic survey was acquired over the area in December 1992. The project was designed not only to evaluate the limits of the Birkhead sand but also to evaluate the cost efficiency of recording such small 3D surveys in the basin.Interpretation of the data set integrated with seismic modelling and seismic attribute analysis delineated a thin Birkhead fluvial channel sand reservoir. Geological pay mapping matched volumetric estimates from production performance data. Structural mapping showed Dirkala-1 to be optimally placed and that no further development drilling was justifiable.Seismic characteristics comparable with those of the Dirkala-1 Birkhead reservoir were noted in another area of the survey beyond field limits. This led to the proposal to drill an exploration well, Dirkala South-1, which discovered a new oil pool in the Birkhead Formation. A post-well audit of the pre-drill modelling confirmed that the seismic response could be used to determine the presence of the Birkhead channel sand reservoir.The acquisition of the Dirkala-3D seismic survey demonstrated the feasibility of conducting small 3D seismic surveys to identify subtle stratigraphically trapped Eromanga Basin accumulations at lower cost and risk than appraisal/development drilling based on 2D seismic data.
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Johns, Rhodri, and Patrick Despland. "2013 PESA industry review: exploration." APPEA Journal 54, no. 1 (2014): 431. http://dx.doi.org/10.1071/aj13043.
Full textAbstract:
Exploration activity in Australia in 2013 occurred across a broad spectrum of conventional and unconventional plays. Competition for acreage was buoyant with large tracts of key onshore basins either licensed or under application. Offshore, there were new awards on the western Australian margin and in the Bight Basin off SA. Offshore 3D seismic acquisition was reduced from anomalously high levels in 2012. Onshore 2D seismic acquisition was at historic highs and onshore 3D was the most ever recorded. Overall drilling levels were maintained despite a decline offshore. Of 13 offshore wells drilled, six were discoveries. Sixty-nine exploration wells (excluding CSG wells) were drilled onshore. Fifty addressed conventional, and 19 were unconventional shale or basin-centered gas targets. Sixty of the 69 wells were drilled in the Cooper/Eromanga Basin where conventional oil and gas exploration yielded 11 oil and six gas discoveries. Drilling and fraccing campaigns in the Nappamerri Trough unconventional gas plays provided early encouraging results. 213 exploration and appraisal CSG wells were drilled in the CSG basins of Queensland and NSW. In Queensland a record total of 1,317 CSG wells were drilled in fiscal year 2012/2013. Shale gas exploration activity was increasingly focused on the Palaeozoic and Proterozoic Basins of Western, Central and Northern Australia with major oil and gas companies involved in joint ventures preparing for drilling in 2014. The results of these programmes will have an important bearing on the future direction of exploration in these plays.
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Miyazaki, S. "CHARACTERISATION OF AUSTRALIA'S OIL FIELDS BY FLUID AND RESERVOIR PROPERTIES AND CONDITIONS." APPEA Journal 29, no. 1 (1989): 287. http://dx.doi.org/10.1071/aj88025.
Full textAbstract:
An extensive data compilation of reservoir rock and fluid properties, and temperature and pressure conditions, in Australia's oil fields, has provided regional information on the nature of crude oil accumulations. It has also allowed the determination of systematic trends and regional variations. These trends and variations are depicted in cross- plots of porosity against depth, porosity against permeability, temperature against depth, pressure against depth, oil gravity against depth, and formation- water salinity against depth.Offshore oil reservoirs, principally based on Gippsland Basin data, are of better quality than onshore ones, even after the porosity cut- off effect is taken into consideration. The Eromanga and Cooper Basins have a higher heat flow than other basins containing oil fields. Pressure trends are consistent with the low salinity nature of formation waters. In Australia, oil reservoirs have an average depth of 1500 m sub- sea and an average temperature of 90°C, and crude oils are light, with an average gravity of 45° API.Interpretation of systematic trends and regional variations can facilitate prospect evaluation by predicting the most likely reservoir qualities and conditions and the fluid properties in potential drilling targets.
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Dunlop, E. C., M. V. Browne, and E. F. Tadiar. "DEPLETION OF GAS RESERVOIRS BY MOLECULAR DIFFUSION — A CASE STUDY." APPEA Journal 32, no. 1 (1992): 369. http://dx.doi.org/10.1071/aj91029.
Full textAbstract:
Recent drilling in the southern Cooper-Eromanga basins of eastern central Australia has provided evidence to suggest that Permian gas reservoirs have been depleted by molecular diffusion.Diffusion is the process by which matter is transported along a concentration gradient, as a result of random molecular motion. It is a common and ubiquitous phenomenon in geological environments.In the Toolachee and Nappacoongee-Murteree blocks of PELs 5 and 6, channel sandstones of the Permian Patchawarra Formation are faulted or subcrop against the Murteree Horst basement high. The Lower-Middle Jurassic Hutton Sandstone was deposited directly over the exposed surface of this feature and the surrounding eroded Permo-Triassic topography. As a result, the truncated Patchawarra Formation sandstone reservoirs are in contact with the overlying Hutton Sandstone, a major fresh water aquifer within the Great Artesian Basin. There is an anomalous increase in Patchawarra Formation water resisitivity around the Murteree Horst, suggesting that fluid communication with the Hutton Sandstone has allowed ionic diffusion to reduce the salinity of the Patchawarra reservoirs.Fluid communication has existed between the Patchawarra and Hutton reservoir systems for the duration of hydrocarbon generation and migration. It is proposed that the diffusion of solution gas towards the Murteree Horst has lowered basinward Patchawarra gas concentrations below saturation point, to the extent that gas generated in nearby source areas has gone into solution rather than migrating in the gaseous phase to form accumulations. Hydrocarbon traps immediately basinward of the Patchawarra edge should contain gas only if the rate of supply from source rocks has been greater than the rate of loss by diffusion. Gas accumulations may be shielded from depletion by source areas or other accumulations which are closer to the Patchawarra edge.The diffusion model has a negative impact on the prospectivity of Permian gas targets in marginal source areas of the Cooper Basin where reservoir communication exists between potential gas reservoirs and the Great Artesian Basin aquifers. Nevertheless, the recognition of this process may be used to advantage in identifying areas where further gas exploration should be curtailed. Such action may improve the drilling success rate in the region.