THE NATURAL CONVERSION OF OIL TO GAS IN SEDIMENTS IN THE COOPER BASIN

1971 ◽  
Vol 11 (1) ◽  
pp. 121
Author(s):  
J.D. Brooks ◽  
W.R. Hesp ◽  
D. Rigby
Keyword(s):  
Oil And Gas ◽  
South Australia ◽  
High Rank ◽  
Average Chain Length ◽  
Low Grade ◽  
Liquid Hydrocarbons ◽  
Gaseous Products ◽  
Underground Gasification ◽  
Long Chain ◽  
Cooper Basin

In the Permian Cooper Basin, South Australia, in which oil and gas occur in coal-bearing sediments, there appears to be a relation between the degree of low grade metamorphism of the coaly matter and the nature of the hydrocarbons in the reservoirs. Liquid hydrocarbons are not found in areas and at depths where the coals are at the high-rank bituminous stage (88-89% carbon, dry mineral-free); there, methane is the main hydrocarbon present. Oil occurs in association with coals of lower rank (80-85% carbon, dry mineral-free) and it seems possible that underground gasification of the liquid hydrocarbons has occurred under natural conditions during advanced coalification.In order to test this, mixtures of long chain paraffins (C10-C28) and (C16-C31) from Kingfish crude oil (East Gippsland Basin) were heated at various pressures, with and without water at temperatures between 255-375°C with the intention of reproducing in one week reactions which might occur at lower temperatures in sediments during geological time.The formation of gaseous products (C1-C4 hydrocarbons; hydrogen and carbon dioxide), light liquid paraffins (C10-C16) and aromatic hydrocarbons was observed. The average chain length of the long chain hydrocarbons was reduced and the effect was more pronounced with the longer chain (C16-C31) fraction. It is concluded that during extended time at temperatures near 400°F which prevail in the deeper parts of the Cooper Basin, gasification reactions involving progressive chain shortening could be responsible for the absence of liquid hydrocarbons in regions where the coals are of the high-rank bituminous type.

EXPLORATION IN THE COOPER BASIN

1989 ◽  
Vol 29 (1) ◽  
pp. 366 ◽  
Author(s):  
R. Heath
Keyword(s):  
Oil And Gas ◽  
South Australia ◽  
Mature Stage ◽  
Small Contribution ◽  
Terrestrial Source ◽  
Seismic Acquisition ◽  
Proterozoic Basement ◽  
Gas Fields ◽  
Coal Measures ◽  
Cooper Basin

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.

Old rocks, new tricks: a reinvigorated Cooper Basin offers growth opportunity

2019 ◽  
Vol 59 (2) ◽  
pp. 928
Author(s):  
Bill Ovenden
Keyword(s):  
Oil And Gas ◽  
Low Cost ◽  
New Technology ◽  
South Australia ◽  
Production Costs ◽  
Imaging Data ◽  
Oil And Gas Development ◽  
North East ◽  
Risk Appetite ◽  
Cooper Basin

The Cooper Basin spans north-east South Australia and south-west Queensland and is Australia’s largest integrated onshore oil and gas development. Santos and Delhi first discovered commercial gas in 1963. First oil was discovered in 1970. Since then, the Cooper Basin has become a strategically important processing and transportation hub for produced gas and liquids. Continuous investment in new technology, the use of existing infrastructure and, recently, an unrelenting drive to lower drilling and production costs has delivered a low-cost, high-margin producer for east coast domestic and liquefied natural gas (LNG) export markets. This improved operating performance has, in turn, offered Santos the opportunity to reassess ‘our backyard’. The Cooper Basin boasts many growth options, remaining and emerging. Seismic advances are providing improved imaging. Data management, the use of play-based exploration studies, innovative geoscience thinking and renewed investment risk appetite are playing key roles in the development of discovered resources and the exploration of new and emerging plays. Targeted wildcat exploration and appraisal programs, supported by low-cost operations, offer the potential to unlock significant remaining oil and gas resources. The Cooper Basin is poised for another stage of growth. This tangible potential emphasises the critical future role the basin is likely to continue to play as an onshore Australian hydrocarbon supply hub.

Fracture mapping and modelling in shale-gas target in the Cooper Basin, South Australia

2011 ◽  
Vol 51 (1) ◽  
pp. 397 ◽  
Author(s):  
Guillaume Backé ◽  
Hani Abul Khair ◽  
Rosalind King ◽  
Simon Holford
Keyword(s):  
Shale Gas ◽  
Seismic Data ◽  
Oil And Gas ◽  
South Australia ◽  
Horizontal Stress ◽  
Fracture Network ◽  
Low Permeability ◽  
Lake Area ◽  
Stress Regime ◽  
Cooper Basin

The success story of a shale-gas reserve development in the United States is triggering a strong industry focus towards similar plays in Australia. The Cooper Basin (located at the border of South Australia and Queensland) and the Otway Basin (extending both onshore and offshore South Australia and Victoria) could be prime targets to develop shale-gas projects. The Cooper Basin, a late-Carboniferous to mid-Triassic basin, is the largest onshore sedimentary basin producing oil and gas from tight conventional reservoirs with low permeability. Fracture stimulation programs are used extensively to produce the oil and gas. Furthermore, new exploration strategies are now targeting possible commercial gas hosted in low-permeability Permian shale units. To maximise production, the development of shale-gas prospects requires a good understanding of the: 1. structure of the reservoirs; 2. mechanical properties of the stratigraphy; 3. fracture geometry and density; 4. in-situ stress field; and, 5. fracture stimulation strategies. In this study, we use a combination of seismic mapping techniques–including horizon and attribute mapping, and an analysis of wellbore geophysical logs–to best constrain the existing fracture network in the basins. This study is based on the processing and analysis of a 3D seismic cube–the Moomba Big Lake survey–which is located in the southwestern part of the Cooper Basin. This dataset covers an area encompassing both a structurally complex setting in the vicinity of a major fault to the SE of the survey, and an area of more subtle deformation corresponding to the southernmost part of the Nappamerri Trough. Structural fabrics trending ˜NW–SE and NE–SW, which are not visible on the amplitude seismic data, are revealed by the analysis of the seismic attributes–namely a similarity (equivalent to a coherency cube), dip steering and maximum curvature attributes. These orientations are similar to those of natural fractures mapped from borehole images logs, and can therefore be interpreted as imaging natural fractures across the Moomba-Big Lake area. This study is the first of its kind able to detect possible fractures from seismic data in the Cooper Basin. The methodology developed here can offer new insights into the structure of sedimentary basins and provide crucial parameters for the development of tight reservoirs. In parallel, a tentative forward model of the generation of a fracture network following a restoration of the Top Roseneath horizon was carried out. The relatively good correlation between the fracture orientations generated by the model and the fractures mapped from geophysical data shows that fractures in the Moomba-Big Lake area may have formed during either a N–S compressive principal horizontal stress, or an E–W compressive principal horizontal tectonic stress regime. In addition, the orientations of the fracture interpreted through this study are also compatible with a generation under the present day stress regime described in this part of the basin, with an maximal horizontal stress trending E–W.

Accelerating oil and gas investment and reserves by design

2018 ◽  
Vol 58 (2) ◽  
pp. 557
Author(s):  
Barry A. Goldstein
Keyword(s):  
Natural Gas ◽  
Fossil Fuels ◽  
Oil And Gas ◽  
South Australia ◽  
Land Access ◽  
Oil And Gas Exploration ◽  
Oil And Gas Producers ◽  
Crude Oil Prices ◽  
Exploration And Production ◽  
Oil And Gas Operations

Facts are stubborn things; and whatever may be our wishes, our inclinations, or the dictates of our passion, they cannot alter the state of facts and evidence (Adams 1770). Some people unfamiliar with upstream petroleum operations, some enterprises keen to sustain uncontested land use, and some people against the use of fossil fuels have and will voice opposition to land access for oil and gas exploration and production. Social and economic concerns have also arisen with Australian domestic gas prices tending towards parity with netbacks from liquefied natural gas (LNG) exports. No doubt, natural gas, LNG and crude-oil prices will vary with local-to-international supply-side and demand-side competition. Hence, well run Australian oil and gas producers deploy stress-tested exploration, delineation and development budgets. With these challenges in mind, successive governments in South Australia have implemented leading-practice legislation, regulation, policies and programs to simultaneously gain and sustain trust with the public and investors with regard to land access for trustworthy oil and gas operations. South Australia’s most recent initiatives to foster reserve growth through welcomed investment in responsible oil and gas operations include the following: a Roundtable for Oil and Gas; evergreen answers to frequently asked questions, grouped retention licences that accelerate investment in the best of play trends; the Plan for ACcelerating Exploration (PACE) Gas Program; and the Oil and Gas Royalty Return Program. Intended and actual outcomes from these initiatives are addressed in this extended abstract.

scholarly journals Transformation of Construction Cement to a Self-Healing Hybrid Binder

2019 ◽  
Vol 20 (12) ◽  
pp. 2948 ◽  
Author(s):  
Werner E.G. Müller ◽  
Emad Tolba ◽  
Shunfeng Wang ◽  
Qiang Li ◽  
Meik Neufurth ◽  
...  
Keyword(s):  
Soil Bacteria ◽  
Construction Material ◽  
Water Soluble ◽  
The Self ◽  
Average Chain Length ◽  
Self Healing ◽  
Cement Concrete ◽  
Low Concentrations ◽  
Natural Mechanism ◽  
Long Chain

A new biomimetic strategy to im prove the self-healing properties of Portland cement is presented that is based on the application of the biogenic inorganic polymer polyphosphate (polyP), which is used as a cement admixture. The data show that synthetic linear polyp, with an average chain length of 40, as well as natural long-chain polyP isolated from soil bacteria, has the ability to support self-healing of this construction material. Furthermore, polyP, used as a water-soluble Na-salt, is subject to Na+/Ca2+ exchange by the Ca2+ from the cement, resulting in the formation of a water-rich coacervate when added to the cement surface, especially to the surface of bacteria-containing cement/concrete samples. The addition of polyP in low concentrations (<1% on weight basis for the solids) not only accelerated the hardening of cement/concrete but also the healing of microcracks present in the material. The results suggest that long-chain polyP is a promising additive that increases the self-healing capacity of cement by mimicking a bacteria-mediated natural mechanism.

Exploring for stratigraphic traps in the Patchawarra Formation, Cooper Basin: an integrated seismic methodology

2018 ◽  
Vol 58 (2) ◽  
pp. 779
Author(s):  
Alexandra Bennett
Keyword(s):  
Complex Geometry ◽  
Imaging Techniques ◽  
South Australia ◽  
Seismic Interpretation ◽  
Seismic Survey ◽  
3D Seismic ◽  
Seismic Resolution ◽  
Seismic Reflectivity ◽  
Seismic Area ◽  
Cooper Basin

The Patchawarra Formation is characterised by Permian aged fluvial sediments. The conventional hydrocarbon play lies within fluvial sandstones, attributed to point bar deposits and splays, that are typically overlain by floodbank deposits of shales, mudstones and coals. The nature of the deposition of these sands has resulted in the discovery of stratigraphic traps across the Western Flank of the Cooper Basin, South Australia. Various seismic techniques are being used to search for and identify these traps. High seismic reflectivity of the coals with the low reflectivity of the relatively thin sands, often below seismic resolution, masks a reservoir response. These factors, combined with complex geometry of these reservoirs, prove a difficult play to image and interpret. Standard seismic interpretation has proven challenging when attempting to map fluvial sands. Active project examples within a 196 km2 3D seismic survey detail an evolving seismic interpretation methodology, which is being used to improve the delineation of potential stratigraphic traps. This involves an integration of seismic processing, package mapping, seismic attributes and imaging techniques. The integrated seismic interpretation methodology has proven to be a successful approach in the discovery of stratigraphic and structural-stratigraphic combination traps in parts of the Cooper Basin and is being used to extend the play northwards into the 3D seismic area discussed.

scholarly journals Aboriginal women have a higher risk of cervical abnormalities at screening; South Australia, 1993–2016

2018 ◽  
Vol 26 (2) ◽  
pp. 104-112
Author(s):  
Ming Li ◽  
David Roder ◽  
Lisa J Whop ◽  
Abbey Diaz ◽  
Peter D Baade ◽  
...  
Keyword(s):  
Cervical Cancer ◽  
Relative Risk ◽  
Confidence Interval ◽  
Cervical Screening ◽  
South Australia ◽  
Low Grade ◽  
High Grade ◽  
Mixed Effect ◽  
Aboriginal Women ◽  
Cytological Abnormality

Objective Cervical cancer mortality has halved in Australia since the national cervical screening program began in 1991, but elevated mortality rates persist for Aboriginal and Torres Strait Islander women (referred to as Aboriginal women in this report). We investigated differences by Aboriginal status in abnormality rates predicted by cervical cytology and confirmed by histological diagnoses among screened women. Methods Using record linkage between cervical screening registry and public hospital records in South Australia, we obtained Aboriginal status of women aged 20–69 for 1993–2016 (this was not recorded by the registry). Differences in cytological abnormalities were investigated by Aboriginal status, using relative risk ratios from mixed effect multinomial logistic regression modelling. Odds ratios were calculated for histological high grade results for Aboriginal compared with non-Aboriginal women. Results Of 1,676,141 linkable cytology tests, 5.8% were abnormal. Abnormal results were more common for women who were younger, never married, and living in a major city or socioeconomically disadvantaged area. After adjusting for these factors and numbers of screening episodes, the relative risk of a low grade cytological abnormality compared with a normal test was 14% (95% confidence interval 5–24%) higher, and the relative risk of a high grade cytological abnormality was 61% (95% confidence interval 44–79%) higher, for Aboriginal women. The adjusted odds ratio of a histological high grade was 76% (95% confidence interval 46–113%) higher. Conclusions Ensuring that screen-detected abnormalities are followed up in a timely way by culturally acceptable services is important for reducing differences in cervical cancer rates between Aboriginal and non-Aboriginal women.

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